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Washington, D.C. 20549
þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the Fiscal Year ended December 31, 2008. | ||
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 | |
Common Stock, par value $0.01 5.75% Mandatory Convertible Preferred Stock | New York Stock Exchange New York Stock Exchange |
Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o |
Class | Outstanding at February 9, 2009 | |
Common Stock, par value $0.01 per share | 236,232,031 |
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AB32 | Assembly Bill 32 — California Global Warming Solutions Act of 2006 | |
ABWR | Advanced Boiling Water Reactor | |
Acquisition | February 2, 2006 acquisition of Texas Genco LLC, now referred to as the Company’s Texas region | |
APB | Accounting Principles Board | |
APB 18 | APB Opinion No. 18,“The Equity Method of Accounting for Investments in Common Stock” | |
APB 23 | APB Opinion No. 23,“Accounting for Income Taxes-Special Areas” | |
ARO | Asset Retirement Obligation | |
Baseload capacity | Electric power generation capacity normally expected to serve loads on an around-the-clock basis throughout the calendar year | |
BP | BP Wind Energy North America Inc. | |
BTA | Best Technology Available | |
BTU | British Thermal Unit | |
CAA | Clean Air Act | |
CAGR | Compound annual growth rate | |
CAIR | Clean Air Interstate Rule | |
CAISO | California Independent System Operator | |
CAMR | Clean Air Mercury Rule | |
Capital Allocation Plan | Share repurchase program | |
Capital Allocation Program | NRG’s plan of allocating capital between debt reduction, reinvestment in the business, and share repurchases through the Capital Allocation Plan. | |
CDWR | California Department of Water Resources | |
CERCLA | Comprehensive Environmental Response, Compensation and Liability Act of 1980 | |
CL&P | The Connecticut Light & Power Company | |
CO2 | Carbon dioxide | |
COLA | Combined Construction and Operating License Application | |
CPUC | California Public Utilities Commission | |
CS | Credit Suisse Group | |
CSF I | NRG Common Stock Finance I LLC | |
CSF II | NRG Common Stock Finance II LLC |
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DNREC | Delaware Department of Natural Resources and Environmental Control | |
DPUC | Department of Public Utility Control | |
EAF | Annual Equivalent Availability Factor, which measures the percentage of maximum generation available over time as the fraction of net maximum generation that could be provided over a defined period of time after all types of outages and deratings, including seasonal deratings, are taken into account | |
EFOR | Equivalent Forced Outage Rates — considers the equivalent impact that forced de-ratings have in addition to full forced outages | |
EITF | Emerging Issues Task Force | |
EITF02-3 | EITF IssueNo. 02-3,“Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” | |
EITF04-6 | EITF IssueNo. 04-6,“Accounting for Stripping Costs Incurred during Production in the Mining Industry” | |
EITF07-5 | EITFNo. 07-5,“Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock” | |
EITF08-5 | EITF08-5,“Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” | |
EITF08-6 | EITF08-6,“Equity Method Investment Accounting Considerations” | |
EPAct of 2005 | Energy Policy Act of 2005 | |
EPC | Engineering, Procurement and Construction | |
ERCOT | Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas | |
ERO | Energy Reliability Organization | |
ESPP | Employee Stock Purchase Plan | |
EWG | Exempt Wholesale Generator | |
Exchange Act | The Securities Exchange Act of 1934, as amended | |
Expected Baseload Generation | The net baseload generation limited by economic factors (relationship between cost of generation and market price) and reliability factors (scheduled and unplanned outages) | |
FASB | Financial Accounting Standards Board — the designated organization for establishing standards for financial accounting and reporting | |
FCM | Forward Capacity Market | |
FERC | Federal Energy Regulatory Commission | |
FIN | FASB Interpretation | |
FIN 45 | FIN No. 45“Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” |
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FIN 46R | FIN No. 46(R),“Consolidation of Variable Interest Entities” | |
FIN 47 | FIN No. 47,“Accounting for Conditional Asset Retirement Obligations” | |
FIN 48 | FIN No. 48,“Accounting for Uncertainty in Income Taxes” | |
FPA | Federal Power Act | |
Fresh Start | Reporting requirements as defined bySOP 90-7 | |
FSP | FASB Staff Position | |
FSP APB14-1 | FSP No. APB14-1,“Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)” | |
FSPFIN 39-1 | FSPNo. FIN 39-1,“Amendment of Financial Interpretation No. 39” | |
FSPFAS 132R-1 | FSP No. FAS 132(R)-1“Employers’ Disclosures about Postretirement Benefit Plan Assets” | |
FSPFAS 133-1 andFIN 45-4 | FSPNo. FAS 133-1 andFIN No. 45-4,“Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and Financial Interpretation Number 45; and Clarification of the Effective Date of FASB Statement No. 161” | |
FSPFAS 140-4 and FIN 46(R)-8 | FSPNo. FAS 140-4 and FIN 46(R)-8,“Disclosures by Public Entities (Enterprises) about Transfers of Financial assets and Interests in Variable Interest Entities” | |
FSPFAS 142-3 | FSPNo. FAS 142-3,“Determination of the Useful Life of Intangible Asset” | |
FSPFAS 157-3 | FSPNo. FAS 157-3,“Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active” | |
GHG | Greenhouse Gases | |
Gross Generation | The total amount of electric energy produced by generating units and measured at the generating terminal in kWh’s or MWh’s | |
Heat Rate | A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWh’s generated. Heat rates can be expressed as either gross or net heat rates, depending whether the electricity output measured is gross or net generation and is generally expressed as BTU per net kWh | |
Hedge Reset | Net settlement of long-term power contracts and gas swaps by negotiating prices to current market completed in November 2006 | |
IGCC | Integrated Gasification Combined Cycle | |
IRS | Internal Revenue Service | |
ISO | Independent System Operator, also referred to as Regional Transmission Organizations, or RTO | |
ISO-NE | ISO New England Inc. | |
ITISA | Itiquira Energetica S.A. | |
kV | Kilovolts |
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kW | Kilowatts | |
kWh | Kilowatt-hours | |
LFRM | Locational Forward Reserve Market | |
LIBOR | London Inter-Bank Offer Rate | |
LMP | Locational Marginal Prices | |
LTIP | Long-Term Incentive Plan | |
MADEP | Massachusetts Department of Environmental Protection | |
MACT | Maximum Achievable Control Technology | |
Merit Order | A term used for the ranking of power stations in order of ascending marginal cost | |
MIBRAG | Mitteldeutsche Braunkohlengesellschaft mbH | |
Moody’s | Moody’s Investors Services, Inc. — a credit rating agency | |
MMBtu | Million British Thermal Units | |
MOU | Memorandum of Understanding | |
MRTU | Market Redesign and Technology Upgrade | |
MW | Megawatts | |
MWh | Saleable megawatt hours net of internal/parasitic loadmegawatt-hours | |
MWt | Megawatts Thermal | |
NAAQS | National Ambient Air Quality Standards | |
NEPOOL | New England Power Pool | |
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, 2008 | |
Net Capacity Factor | The net amount of electricity that a generating unit produces over a period of time divided by the net amount of electricity it could have produced if it had run at full power over that time period. The net amount of electricity produced is the total amount of electricity generated minus the amount of electricity used during generation. | |
Net Exposure | Counterparty credit exposure to NRG, net of collateral | |
Net Generation | The net amount of electricity produced, expressed in kWh’s or MWh’s, that is the total amount of electricity generated (gross) minus the amount of electricity used during generation. | |
New York Rest of State | New York State excluding New York City | |
NINA | Nuclear Innovation North America LLC | |
NOx | Nitrogen oxide | |
NOL | Net Operating Loss | |
NOV | Notice of Violation | |
NPNS | Normal Purchase Normal Sale |
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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 | |
Padoma | Padoma Wind Power LLC | |
Phase II 316(b) Rule | A section of the Clean Water Act regulating cooling water intake structures | |
PJM | PJM Interconnection, LLC | |
PJM market | The wholesale and retail electric market operated by PJM primarily in all or parts of Delaware, the District of Columbia, Illinois, Maryland, New Jersey, Ohio, Pennsylvania, Virginia and West Virginia | |
PMI | NRG Power Marketing, LLC, a wholly-owned subsidiary of NRG which procures transportation and fuel for the Company’s generation facilities, sells the power from these facilities, and manages all commodity trading and hedging for NRG | |
Powder River Basin, or PRB, Coal | Coal produced in northeastern Wyoming and southeastern Montana, which has low sulfur content | |
PPA | Power Purchase Agreement | |
PPM | Parts per Million | |
PSD | Prevention of Significant Deterioration | |
PUCT | Public Utility Commission of Texas | |
PUHCA of 2005 | Public Utility Holding Company Act of 2005 | |
PURPA | Public Utility Regulatory Policy Act of 2005 | |
Repowering | Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility, not only to achieve a substantial emissions reduction, but also to increase facility capacity, and improve system efficiency | |
RepoweringNRG | NRG’s program designed to develop, finance, construct and operate new, highly efficient, environmentally responsible capacity over the next decade | |
Revolving Credit Facility | NRG’s $1 billion senior secured credit facility which matures on February 2, 2011 | |
RGGI | Regional Greenhouse Gas Initiative | |
RMR | Reliability Must-Run | |
ROIC | Return on invested capital | |
RPM | Reliability Pricing Model — term for capacity market in PJM market | |
RTO | Regional Transmission Organization, also referred to as an Independent System Operators, or ISO |
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S&P | Standard & Poor’s, a credit rating agency | |
SARA | Superfund Amendments and Reauthorization Act of 1986 | |
Sarbanes-Oxley | Sarbanes — Oxley Act of 2002 | |
Schkopau | Kraftwerk Schkopau Betriebsgesellschaft mbH, an entity in which NRG has a 41.9% interest | |
SCR | Selective Catalytic Reduction | |
SEC | United States Securities and Exchange Commission | |
Securities Act | The Securities Act of 1933, as amended | |
Senior Credit Facility | NRG’s senior secured facility, which is comprised of a Term Loan Facility and a $1.3 billion Synthetic Letter of Credit Facility which matures on February 1, 2013, and a $1 billion Revolving Credit Facility, which matures on February 2, 2011. | |
Senior Notes | The Company’s $4.7 billion outstanding unsecured senior notes consisting of $1.2 billion of 7.25% senior notes due 2014, $2.4 billion of 7.375% senior notes due 2016 and $1.1 billion of 7.375% senior notes due 2017 | |
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 106 | SFAS No. 106,“Employers’ Accounting for Postretirement Benefits Other Than Pensions” | |
SFAS 109 | SFAS No. 109,“Accounting for Income Taxes” | |
SFAS 123R | SFAS No. 123 (revised 2004),“Share-Based Payment” | |
SFAS 133 | SFAS No. 133,“Accounting for Derivative Instruments and Hedging Activities” as amended | |
SFAS 141 | SFAS No. 141,“Business Combinations” | |
SFAS 141R | SFAS No. 141 (revised 2007),“Business Combinations” | |
SFAS 142 | SFAS No. 142,“Goodwill and Other Intangible Assets” | |
SFAS 143 | SFAS No. 143,“Accounting for Asset Retirement Obligations” | |
SFAS 144 | SFAS No. 144,“Accounting for the Impairment or Disposal of Long-Lived Assets” | |
SFAS 157 | SFAS No. 157,“Fair Value Measurement” | |
SFAS 158 | SFAS No. 158,“Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R)” | |
SFAS 159 | SFAS No. 159,“The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FASB Statement No. 115” | |
SFAS 160 | SFAS No. 160,“Noncontrolling Interest in Consolidated Financial Statements” |
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SFAS 161 | SFAS No. 161,“Disclosure about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” | |
Sherbino | Sherbino I Wind Farm LLC | |
SO2 | Sulfur dioxide | |
SOP | Statement of Position issued by the American Institute of Certified Public Accountants | |
SOP 90-7 | Statement of Position90-7,“Financial Reporting by Entities in Reorganization Under the Bankruptcy Code” | |
STP | South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% Interest | |
STPNOC | South Texas Project Nuclear Operating Company | |
Synthetic Letter of Credit Facility | NRG’s $1.3 billion senior secured synthetic letter of credit facility which matures on February 1, 2013 | |
TCEQ | Texas Commission on Environmental Quality | |
Term Loan Facility | A senior first priority secured term loan which matures on February 1, 2013, and is included as part of NRG’s Senior Credit Facility. | |
Texas Genco | Texas Genco LLC, now referred to as the Company’s Texas Region | |
Tonnes | Metric tonnes, which are units of mass or weight in the metric system each equal to 2,205 lbs and are the global Measurement for GHG | |
Tosli | Tosli Acquisition B.V. | |
Uprate | A sustainable increase in the electrical rating of a generating facility | |
US | United States of America | |
USEPA | United States Environmental Protection Agency | |
US GAAP | Accounting principles generally accepted in the United States | |
VAR | Value at Risk | |
WCP | WCP (Generation) Holdings, Inc. |
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Item 1 — | Business |
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Risk | Total | |||||||||||||||||||||||||||
Energy | Capacity | Management | Contract | Thermal | Other | Operating | ||||||||||||||||||||||
Region | Revenues | Revenues | Activities | Amortization | Revenues | Revenues | Revenues | |||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||
Texas | $ | 2,870 | $ | 493 | $ | 318 | $ | 255 | $ | — | $ | 90 | $ | 4,026 | ||||||||||||||
Northeast | 1,064 | 415 | 85 | — | — | 66 | 1,630 | |||||||||||||||||||||
South Central | 478 | 233 | 10 | 23 | — | 2 | 746 | |||||||||||||||||||||
West | 39 | 125 | — | — | — | 7 | 171 | |||||||||||||||||||||
International | 56 | 86 | — | — | — | 16 | 158 | |||||||||||||||||||||
Thermal | 12 | 7 | 5 | — | 114 | 16 | 154 | |||||||||||||||||||||
Corporate and Eliminations | — | — | — | — | — | — | — | |||||||||||||||||||||
Total | $ | 4,519 | $ | 1,359 | $ | 418 | $ | 278 | $ | 114 | $ | 197 | $ | 6,885 | ||||||||||||||
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Year Ended December 31, 2008 | ||||||||||||||||||||
Annual | ||||||||||||||||||||
Net | Equivalent | Average Net | ||||||||||||||||||
Net Owned | Generation | Availability | Heat Rate | Net Capacity | ||||||||||||||||
Region | Capacity (MW) | (MWh) | Factor | Btu/kWh | Factor | |||||||||||||||
(In thousands of MWh) | ||||||||||||||||||||
Texas(a) | 11,010 | 46,937 | 88.1 | % | 10,300 | 49.6 | % | |||||||||||||
Northeast(b) | 7,020 | 13,349 | 88.8 | 10,800 | 19.9 | |||||||||||||||
South Central | 2,845 | 11,148 | 93.4 | 10,300 | 47.6 | |||||||||||||||
West | 2,130 | 1,532 | 91.5 | % | 11,800 | 10.2 | % |
Year Ended December 31, 2007 | ||||||||||||||||||||
Annual | ||||||||||||||||||||
Net | Equivalent | Average Net | ||||||||||||||||||
Net Owned | Generation | Availability | Heat Rate | Net Capacity | ||||||||||||||||
Region | Capacity (MW) | (MWh) | Factor | Btu/kWh | Factor | |||||||||||||||
(In thousands of MWh) | ||||||||||||||||||||
Texas | 10,805 | 47,779 | 87.6 | % | 10,300 | 50.7 | % | |||||||||||||
Northeast(b) | 6,980 | 14,163 | 83.6 | 10,900 | 21.2 | |||||||||||||||
South Central | 2,850 | 10,930 | 89.0 | 10,200 | 46.1 | |||||||||||||||
West | 2,130 | 1,246 | 89.9 | % | 11,200 | 9.3 | % |
(a) | Net generation (MWh) does not include Sherbino, which is accounted for under the equity method. | |
(b) | Factor data and heat rate do not include the Keystone and Conemaugh facilities. |
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(1) | Includes 115 MW as part of NRG’s Thermal assets. For combined scale, approximately 3,450 MW is dual-fuel capable. Reflects only domestic generation capacity as of December 31, 2008. |
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Annual | ||||||||||||||||||||||||||||
Average for | ||||||||||||||||||||||||||||
2009 | 2010 | 2011 | 2012 | 2013 | 2014 | 2009-2014 | ||||||||||||||||||||||
(Dollars in millions unless otherwise stated) | ||||||||||||||||||||||||||||
Net Baseload Capacity (MW) | 8,701 | 8,539 | 8,459 | 8,432 | 8,432 | 8,432 | 8,499 | |||||||||||||||||||||
Forecasted Baseload Capacity (MW) | 7,497 | 7,229 | 7,164 | 7,232 | 7,324 | 7,395 | 7,307 | |||||||||||||||||||||
Total Baseload Sales (MW)(a) | 7,156 | 5,686 | 4,825 | 3,272 | 1,988 | 789 | 3,953 | |||||||||||||||||||||
Percentage Baseload Capacity Sold Forward(b) | 95 | % | 79 | % | 67 | % | 45 | % | 27 | % | 11 | % | 54 | % | ||||||||||||||
Total Forward Hedged Revenues(c)(d) | $ | 3,851 | $ | 2,905 | $ | 2,200 | $ | 1,670 | $ | 958 | $ | 368 | $ | 1,992 | ||||||||||||||
Weighted Average Hedged Price ($ per MWh)(c) | $ | 61 | $ | 58 | $ | 52 | $ | 58 | $ | 55 | $ | 53 | $ | 58 | ||||||||||||||
Weighted Average Hedged Price ($ per MWh) excluding South Central region(d) | $ | 65 | $ | 62 | $ | 54 | $ | 65 | $ | 66 | $ | — | $ | 62 | ||||||||||||||
Average Equivalent Natural Gas Price ($ per MMBtu) | $ | 8.06 | $ | 7.92 | $ | 7.09 | $ | 7.85 | $ | 7.43 | $ | 7.24 | $ | 7.72 | ||||||||||||||
Average Equivalent Natural Gas Price ($ per MMBtu) excluding South Central region | $ | 8.37 | $ | 8.16 | $ | 7.27 | $ | 8.60 | $ | 8.86 | $ | — | $ | 8.13 |
(a) | Includes amounts under power sales contracts and natural gas hedges. The forward natural gas quantities are reflected in equivalent MWh based on forward market implied heat rate as of December 31, 2008 and then combined with power sales to arrive at equivalent MWh hedged which is then divided by 8,760 hours (8,784 hours in 2012) to arrive at MW hedged. | |
(b) | Percentage hedged is based on total MW sold as power and natural gas converted using the method as described in (a) above divided by the forecasted baseload capacity. | |
(c) | Represents all North American baseload sales, including energy revenue and demand charge. | |
(d) | The South Central region’s weighted average hedged prices ranges from $43/MWh — $53/MWh due to legacy cooperative load contracts entered into at prices significantly below current market levels. These prices include a fixed capacity charge and an estimated energy charge. |
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Percentage of | ||||
Company’s | ||||
Requirement(a) | ||||
2009 | 104 | % | ||
2010 | 69 | % | ||
2011 | 55 | % | ||
2012 | 47 | % | ||
2013 | 18 | % | ||
2014 | 12 | % |
(a) | The hedge percentages reflect the current plan for the Jewett mine. NRG has the contractual ability to change volumes and may do so in the future. |
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Texas | Northeast | South Central | Total | |||||||||||||
(In millions) | ||||||||||||||||
2009 | $ | — | $ | 256 | $ | — | $ | 256 | ||||||||
2010 | 8 | 213 | 57 | 278 | ||||||||||||
2011 | 17 | 175 | 116 | 308 | ||||||||||||
2012 | 29 | 67 | 114 | 210 | ||||||||||||
2013 | 21 | 3 | 74 | 98 | ||||||||||||
Total | $ | 75 | $ | 714 | $ | 361 | $ | 1,150 | ||||||||
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Net Generation | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands of MWh) | ||||||||||||
Coal | 32,825 | 32,648 | 31,371 | |||||||||
Gas | 4,647 | 5,407 | 7,983 | |||||||||
Nuclear(a) | 9,456 | 9,724 | 9,385 | |||||||||
Wind | 9 | — | — | |||||||||
Total | 46,937 | 47,779 | 48,739 | |||||||||
(a) | MWh information reflects the undivided interest in total MWh generated by STP. |
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Net | ||||||||||||
Generation | ||||||||||||
Capacity | Primary | |||||||||||
Plant | Location | % Owned | (MW)(c) | Fuel-type | ||||||||
Solid Fuel Baseload Units: | ||||||||||||
W. A. Parish(a) | Thompsons, TX | 100.0 | 2,475 | Coal | ||||||||
Limestone | Jewett, TX | 100.0 | 1,690 | Lignite/Coal | ||||||||
South Texas Project(b) | Bay City, TX | 44.0 | 1,175 | Nuclear | ||||||||
Total Solid Fuel Baseload | 5,340 | |||||||||||
Intermittent Units: | ||||||||||||
Elbow Creek | Howard County, TX | 100.0 | 120 | Wind | ||||||||
Sherbino | Pecos County, TX | 50.0 | 75 | Wind | ||||||||
Total Intermittent Baseload | 195 | |||||||||||
Operating Natural Gas-Fired Units: | ||||||||||||
Cedar Bayou | Baytown, TX | 100.0 | 1,495 | Natural Gas | ||||||||
T. H. Wharton | Houston, TX | 100.0 | 1,025 | Natural Gas | ||||||||
W. A. Parish(a) | Thompsons, TX | 100.0 | 1,190 | Natural Gas | ||||||||
S. R. Bertron | Deer Park, TX | 100.0 | 840 | Natural Gas | ||||||||
Greens Bayou | Houston, TX | 100.0 | 760 | Natural Gas | ||||||||
San Jacinto | LaPorte, TX | 100.0 | 165 | Natural Gas | ||||||||
Total Operating Natural Gas-Fired | 5,475 | |||||||||||
Total Operating Capacity | 11,010 | |||||||||||
(a) | W. A. Parish has nine units, four of which are baseload coal-fired units and five of which are natural gas-fired units. | |
(b) | Generation capacity figure consists of the Company’s 44.0% undivided interest in the two units at STP. | |
(c) | Actual capacity can vary depending on factors including weather conditions, operational conditions and other factors. The ERCOT requires periodic demonstration of capability, and the capacity may vary individually and in the aggregate from time to time. Excludes 2,200 MW of mothballed capacity available for redevelopment. |
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Net Generation | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands of MWh) | ||||||||||||
Coal | 11,506 | 11,527 | 11,042 | |||||||||
Oil | 349 | 1,169 | 1,217 | |||||||||
Gas | 1,494 | 1,467 | 1,050 | |||||||||
Total | 13,349 | 14,163 | 13,309 | |||||||||
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Net | ||||||||||||
Generation | ||||||||||||
Capacity | Primary | |||||||||||
Plant | Location | % Owned | (MW) | Fuel-type | ||||||||
Oswego | Oswego, NY | 100.0 | 1,635 | Oil | ||||||||
Arthur Kill | Staten Island, NY | 100.0 | 865 | Natural Gas | ||||||||
Middletown | Middletown, CT | 100.0 | 770 | Oil | ||||||||
Indian River | Millsboro, DE | 100.0 | 740 | Coal | ||||||||
Astoria Gas Turbines | Queens, NY | 100.0 | 550 | Natural Gas | ||||||||
Huntley | Tonawanda, NY | 100.0 | 380 | Coal | ||||||||
Dunkirk | Dunkirk, NY | 100.0 | 530 | Coal | ||||||||
Montville | Uncasville, CT | 100.0 | 500 | Oil | ||||||||
Norwalk Harbor | So. Norwalk, CT | 100.0 | 340 | Oil | ||||||||
Devon | Milford, CT | 100.0 | 140 | Natural Gas | ||||||||
Vienna | Vienna, MD | 100.0 | 170 | Oil | ||||||||
Somerset Power(a) | Somerset, MA | 100.0 | 125 | Coal | ||||||||
Connecticut Remote Turbines | Four locations in CT | 100.0 | 145 | Oil/Natural Gas | ||||||||
Conemaugh | New Florence, PA | 3.7 | 65 | Coal | ||||||||
Keystone | Shelocta, PA | 3.7 | 65 | Coal | ||||||||
Total Northeast Region | 7,020 | |||||||||||
(a) | Somerset had previously entered into an agreement with the Massachusetts Department of Environmental Protection, or MADEP, to retire or repower the remaining coal-fired unit at Somerset by the end of 2009. In connection with a repowering proposal approved by the MADEP, the date for the shut-down of the unit was extended to September 30, 2010. |
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Net Generation | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In thousands of MWh) | ||||||||||||
Coal | 10,912 | 10,812 | 10,968 | |||||||||
Gas | 236 | 118 | 68 | |||||||||
Total | 11,148 | 10,930 | 11,036 | |||||||||
Net | ||||||||||||
Generation | ||||||||||||
Capacity | Primary Fuel | |||||||||||
Plant | Location | % Owned | (MW) | type | ||||||||
Big Cajun II(a) | New Roads, LA | 86.0 | 1,490 | Coal | ||||||||
Bayou Cove | Jennings, LA | 100.0 | 300 | Natural Gas | ||||||||
Big Cajun I — (Peakers) Units 3 and 4 | Jarreau, LA | 100.0 | 210 | Natural Gas | ||||||||
Big Cajun I — Units 1 and 2 | Jarreau, LA | 100.0 | 220 | Natural Gas/Oil | ||||||||
Rockford I | Rockford, IL | 100.0 | 300 | Natural Gas | ||||||||
Rockford II | Rockford, IL | 100.0 | 150 | Natural Gas | ||||||||
Sterlington | Sterlington, LA | 100.0 | 175 | Natural Gas | ||||||||
Total South Central | 2,845 | |||||||||||
(a) | NRG owns 100% of Units 1 & 2; 58% of Unit 3 |
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Net | ||||||||||||
Generation | ||||||||||||
Capacity | Primary | |||||||||||
Plant | Location | % Owned | (MW) | Fuel-type | ||||||||
Encina | Carlsbad, CA | 100.0 | 965 | Natural Gas | ||||||||
El Segundo | El Segundo, CA | 100.0 | 670 | Natural Gas | ||||||||
Long Beach | Long Beach, CA | 100.0 | 260 | Natural Gas | ||||||||
Cabrillo II | San Diego, CA | 100.0 | 190 | Natural Gas | ||||||||
Saguaro | Henderson, NV | 50.0 | 45 | Natural Gas | ||||||||
Total West Region | 2,130 | |||||||||||
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Net | ||||||||||||
Generation | ||||||||||||
Capacity | Primary | |||||||||||
Plant | Location | % Owned | (MW) | Fuel-type | ||||||||
Gladstone | Australia | 37.5 | 605 | Coal | ||||||||
Schkopau | Germany | 41.9 | 400 | Lignite | ||||||||
MIBRAG | Germany | 50.0 | 75 | Lignite | ||||||||
Total International | 1,080 | |||||||||||
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Item 1A — | Risk Factors Related to NRG Energy, Inc. |
• | changes in generation capacity in the Company’s markets, including the addition of new supplies of power from existing competitors or new market entrants as a result of the development of new generation plants, expansion of existing plants or additional transmission capacity; | |
• | electric supply disruptions, including plant outages and transmission disruptions; | |
• | changes in power transmission infrastructure; | |
• | fuel transportation capacity constraints; | |
• | weather conditions; | |
• | changes in the demand for power or in patterns of power usage, including the potential development of demand-side management tools and practices; | |
• | development of new fuels and new technologies for the production of power; | |
• | regulations and actions of the ISOs; and | |
• | federal and state power market and environmental regulation and legislation. |
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• | weather conditions; | |
• | seasonality; | |
• | demand for energy commodities and general economic conditions; | |
• | disruption or other constraints or inefficiencies of electricity, gas or coal transmission or transportation; | |
• | additional generating capacity; | |
• | availability and levels of storage and inventory for fuel stocks; | |
• | natural gas, crude oil, refined products and coal production levels; | |
• | changes in market liquidity; | |
• | federal, state and foreign governmental regulation and legislation; and | |
• | the creditworthiness and liquidity and willingness of fuel suppliers/transporters to do business with the Company. |
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• | delays in obtaining necessary permits and licenses; | |
• | environmental remediation of soil or groundwater at contaminated sites; | |
• | interruptions to dispatch at the Company’s facilities; | |
• | supply interruptions; | |
• | work stoppages; | |
• | labor disputes; | |
• | weather interferences; | |
• | unforeseen engineering, environmental and geological problems; | |
• | unanticipated cost overruns; | |
• | exchange rate risks; and | |
• | performance risks. |
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• | fluctuations in currency valuation; | |
• | currency inconvertibility; | |
• | expropriation and confiscatory taxation; | |
• | restrictions on the repatriation of capital; and | |
• | approval requirements and governmental policies limiting returns to foreign investors. |
• | increasing NRG’s vulnerability to general economic and industry conditions; | |
• | requiring a substantial portion of NRG’s cash flow from operations to be dedicated to the payment of principal and interest on its indebtedness, therefore reducing NRG’s ability to pay dividends to holders of its |
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preferred or common stock or to use its cash flow to fund its operations, capital expenditures and future business opportunities; |
• | limiting NRG’s ability to enter into long-term power sales or fuel purchases which require credit support; | |
• | exposing NRG to the risk of increased interest rates because certain of its borrowings, including borrowings under its new senior secured credit facility are at variable rates of interest; | |
• | limiting NRG’s ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; and | |
• | limiting NRG’s ability to adjust to changing market conditions and placing it at a competitive disadvantage compared to its competitors who have less debt. |
• | general economic and capital market conditions; | |
• | credit availability from banks and other financial institutions; | |
• | investor confidence in NRG, its partners and the regional wholesale power markets; | |
• | NRG’s financial performance and the financial performance of its subsidiaries; | |
• | NRG’s level of indebtedness and compliance with covenants in debt agreements; | |
• | maintenance of acceptable credit ratings; | |
• | cash flow; and | |
• | provisions of tax and securities laws that may impact raising capital. |
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• | General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel; | |
• | Hazards customary to the power production industry and power generation operations such as fuel and electricity price volatility, unusual weather conditions, catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that NRG may not have adequate insurance to cover losses as a result of such hazards; | |
• | The effectiveness of NRG’s risk management policies and procedures, and the ability of NRG’s counterparties to satisfy their financial commitments; | |
• | Counterparties’ collateral demands and other factors affecting NRG’s liquidity position and financial condition; | |
• | NRG’s ability to operate its businesses efficiently, manage capital expenditures and costs tightly, and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations; | |
• | NRG’s ability to enter into contracts to sell power and procure fuel on acceptable terms and prices; | |
• | The liquidity and competitiveness of wholesale markets for energy commodities; | |
• | Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws and increased regulation of carbon dioxide and other greenhouse gas emissions; | |
• | Price mitigation strategies and other market structures employed by ISOs or RTOs that result in a failure to adequately compensate NRG’s generation units for all of its costs; | |
• | NRG’s ability to borrow additional funds and access capital markets, as well as NRG’s substantial indebtedness and the possibility that NRG may incur additional indebtedness going forward; | |
• | Operating and financial restrictions placed on NRG and its subsidiaries that are contained in the indentures governing NRG’s outstanding notes, in NRG’s Senior Credit Facility, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally; | |
• | NRG’s ability to implement itsRepoweringNRG strategy of developing and building new power generation facilities, including new nuclear units and wind projects; | |
• | NRG’s ability to implement its econrg strategy of finding ways to meet the challenges of climate change, clean air and protecting our natural resources while taking advantage of business opportunities; and | |
• | NRG’s ability to achieve its strategy of regularly returning capital to shareholders. |
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Item 1B — | Unresolved Staff Comments |
Item 2 — | Properties |
Net | ||||||||||||
Power | Generation | Primary | ||||||||||
Name and Location of Facility | Market | % Owned | Capacity (MW) | Fuel-type | ||||||||
Texas Region: | ||||||||||||
W. A. Parish, Thompsons, Texas | ERCOT | 100.0 | 2,475 | Coal | ||||||||
Limestone, Jewett, Texas | ERCOT | 100.0 | 1,690 | Lignite/Coal | ||||||||
South Texas Project, Bay City, Texas(a) | ERCOT | 44.0 | 1,175 | Nuclear | ||||||||
Cedar Bayou, Baytown, Texas | ERCOT | 100.0 | 1,495 | Natural Gas | ||||||||
T. H. Wharton, Houston, Texas | ERCOT | 100.0 | 1,025 | Natural Gas | ||||||||
W. A. Parish, Thompsons, Texas | ERCOT | 100.0 | 1,190 | Natural Gas | ||||||||
S. R. Bertron, Deer Park, Texas | ERCOT | 100.0 | 840 | Natural Gas | ||||||||
Greens Bayou, Houston, Texas | ERCOT | 100.0 | 760 | Natural Gas | ||||||||
San Jacinto, LaPorte, Texas | ERCOT | 100.0 | 165 | Natural Gas | ||||||||
Elbow Creek Wind Farm, Howard County, Texas | ERCOT | 100.0 | 120 | Wind | ||||||||
Sherbino Wind Farm, Pecos County, Texas | ERCOT | 50.0 | 75 | Wind | ||||||||
Northeast Region: | ||||||||||||
Oswego, New York | NYISO | 100.0 | 1,635 | Oil | ||||||||
Arthur Kill, Staten Island, New York | NYISO | 100.0 | 865 | Natural Gas | ||||||||
Middletown, Connecticut | ISO-NE | 100.0 | 770 | Oil | ||||||||
Indian River, Millsboro, Delaware | PJM | 100.0 | 740 | Coal | ||||||||
Astoria Gas Turbines, Queens, New York | NYISO | 100.0 | 550 | Natural Gas | ||||||||
Dunkirk, New York | NYISO | 100.0 | 530 | Coal | ||||||||
Huntley, Tonawanda, New York | NYISO | 100.0 | 380 | Coal | ||||||||
Montville, Uncasville, Connecticut | ISO-NE | 100.0 | 500 | Oil | ||||||||
Norwalk Harbor, So. Norwalk, Connecticut | ISO-NE | 100.0 | 340 | Oil | ||||||||
Devon, Milford, Connecticut | ISO-NE | 100.0 | 140 | Natural Gas | ||||||||
Vienna, Maryland | PJM | 100.0 | 170 | Oil | ||||||||
Somerset, Massachusetts | ISO-NE | 100.0 | 125 | Coal | ||||||||
Connecticut Jet Power, Connecticut (four sites) | ISO-NE | 100.0 | 145 | Oil/Natural Gas | ||||||||
Conemaugh, New Florence, Pennsylvania | PJM | 3.7 | 65 | Coal | ||||||||
Keystone, Shelocta, Pennsylvania | PJM | 3.7 | 65 | Coal |
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Net | ||||||||||||
Power | Generation | Primary | ||||||||||
Name and Location of Facility | Market | % Owned | Capacity (MW) | Fuel-type | ||||||||
South Central Region: | ||||||||||||
Big Cajun II, New Roads, Louisiana(b) | SERC-Entergy | 86.0 | 1,490 | Coal | ||||||||
Bayou Cove, Jennings, Louisiana | SERC-Entergy | 100.0 | 300 | Natural Gas | ||||||||
Big Cajun I, Jarreau, Louisiana | SERC-Entergy | 100.0 | 210 | Natural Gas | ||||||||
Big Cajun I, Jarreau, Louisiana | SERC-Entergy | 100.0 | 220 | Natural Gas/Oil | ||||||||
Rockford I, Illinois | PJM | 100.0 | 300 | Natural Gas | ||||||||
Rockford II, Illinois | PJM | 100.0 | 150 | Natural Gas | ||||||||
Sterlington, Louisiana | SERC-Entergy | 100.0 | 175 | Natural Gas | ||||||||
West Region: | ||||||||||||
Encina, Carlsbad, California | CAISO | 100.0 | 965 | Natural Gas | ||||||||
El Segundo Power, California | CAISO | 100.0 | 670 | Natural Gas | ||||||||
Long Beach, California | CAISO | 100.0 | 260 | Natural Gas | ||||||||
San Diego Combustion Turbines, California (three sites) | CAISO | 100.0 | 190 | Natural Gas | ||||||||
Saguaro Power Co., Henderson, Nevada | WECC | 50.0 | 45 | Natural Gas | ||||||||
International Region: | ||||||||||||
Gladstone Power Station, Queensland, Australia | Enertrade/Boyne Smelter | 37.5 | 605 | Coal | ||||||||
Schkopau Power Station, Germany | Vattenfall Europe | 41.9 | 400 | Lignite | ||||||||
MIBRAG, Germany(c) | Schkopau, Lippendorf & ENVIA | 50.0 | 75 | Lignite |
(a) | For the nature of NRG’s interest and various limitations on the Company’s interest, please read Item 1 — Business — Texas — Generation Facilities section | |
(b) | Units 1 and 2 owned 100.0%, Unit 3 owned 58.0% | |
(c) | Primarily a coal mining facility |
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% | ||||||||
Ownership | ||||||||
Name and Location of Facility | Thermal Energy Purchaser | Interest | Generating Capacity | |||||
NRG Energy Center Minneapolis, Minnesota | Approx. 100 steam customers and 50 chilled water customers | 100.0 | Steam: 1,143 MMBtu/hr. (335 MWt) Chilled Water: 40,630 tons (143 MWt) | |||||
NRG Energy Center San Francisco, California | Approx. 170 steam customers | 100.0 | Steam: 454 MMBtu/Hr. (133 MWt) | |||||
NRG Energy Center Harrisburg, Pennsylvania | Approx. 210 steam customers and 3 chilled water customers | 100.0 | Steam: 440 MMBtu/hr. (129 MWt) Chilled water: 2,400 tons (8 MWt) | |||||
NRG Energy Center Pittsburgh, Pennsylvania | Approx. 25 steam and 25 chilled water customers | 100.0 | Steam: 296 MMBtu/hr. (87 MWt) Chilled water: 12,920 tons (45 MWt) | |||||
NRG Energy Center San Diego, California | Approx. 20 chilled water customers | 100.0 | Chilled water: 7,425 tons (26 MWt) | |||||
Camas Power Boiler Camas, Washington | Georgia-Pacific Corp. | 100.0 | Steam: 200 MMBtu/hr. (59 MWt) | |||||
NRG Energy Center Dover, Delaware | Kraft Foods Inc. and Procter & Gamble Company | 100.0 | Steam: 190 MMBtu/hr. (56 MWt) | |||||
Paxton Creek Cogeneration, Harrisburg, Pennsylvania | PJM | 100.0 | 12 MW — Natural Gas | |||||
Dover Cogeneration, Delaware | PJM | 100.0 | 104 MW — Natural Gas/Coal |
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Item 3 — | Legal Proceedings |
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Item 4 — | Submission of Matters to a Vote of Security Holders |
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Item 5 — | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Fourth | Third | Second | First | Fourth | Third | Second | First | |||||||||||||||||||||||||
Common Stock | Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | Quarter | ||||||||||||||||||||||||
Price | 2008 | 2008 | 2008 | 2008 | 2007 | 2007 | 2007 | 2007 | ||||||||||||||||||||||||
High | $ | 25.40 | $ | 43.95 | $ | 45.78 | $ | 43.96 | $ | 47.19 | $ | 45.08 | $ | 45.93 | $ | 37.10 | ||||||||||||||||
Low | 14.39 | 22.20 | 38.36 | 34.56 | 38.79 | 34.76 | 35.98 | 27.22 | ||||||||||||||||||||||||
Closing | $ | 23.33 | $ | 24.75 | $ | 42.90 | $ | 38.99 | $ | 43.34 | $ | 42.29 | $ | 41.57 | $ | 36.02 |
Total Number | ||||||||||||||||
of Shares | ||||||||||||||||
Purchased as | Dollar Value of | |||||||||||||||
Part of Publicly | Shares that may be | |||||||||||||||
Total Number of | Average Price | Announced Plans | Purchased Under the | |||||||||||||
For the Year Ended December 31, 2008 | Shares Purchased | Paid per Share | or Programs | Plans or Programs | ||||||||||||
First quarter | 1,281,600 | $ | 42.73 | 1,281,600 | $ | 160,008,401 | ||||||||||
Second quarter | — | — | — | 160,008,401 | ||||||||||||
Third quarter | 3,410,283 | 38.06 | 3,410,283 | 30,226,541 | ||||||||||||
Fourth quarter | — | — | — | 30,226,541 | ||||||||||||
Total for 2008 | 4,691,883 | $ | 39.33 | 4,691,883 | $ | 30,226,541 | ||||||||||
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(c) | ||||||||||||
(b) | Number of Securities | |||||||||||
(a) | Weighted-Average Exercise | Remaining Available | ||||||||||
Number of Securities | Price of Outstanding | for Future Issuance | ||||||||||
to be Issued Upon | Options, Warrants and | Under Compensation | ||||||||||
Exercise of | Rights (Excluding | Plans (Excluding | ||||||||||
Outstanding Options, | Securities Reflected in | Securities Reflected | ||||||||||
Plan Category | Warrants and Rights | Column (a) | in Column (a)) | |||||||||
Equity compensation plans approved by security holders | 6,650,080 | $ | 25.84 | 6,798,074 | (a) | |||||||
Equity compensation plans not approved by security holders | — | N/A | — | |||||||||
Total | 6,650,080 | $ | 25.84 | 6,798,074 | ||||||||
(a) | Consists of NRG Energy, Inc.’s Long-Term Incentive Plan, or the LTIP, and NRG Energy, Inc.’s Employee Stock Purchase Plan, or the ESPP. The LTIP became effective upon the Company’s emergence from bankruptcy. The LTIP was subsequently approved by the Company’s stockholders on August 4, 2004 and was amended on April 28, 2006 to increase the number of shares available for issuance to 16,000,000, on a post-split basis, and again on December 8, 2006 to make technical and administrative changes. The LTIP provides for grants of stock options, stock appreciation rights, restricted stock, performance units, deferred stock units and dividend equivalent rights. NRG’s directors, officers and employees, as well as other individuals performing services for, or to whom an offer of employment has been extended by the Company, are eligible to receive grants under the LTIP. The purpose of the LTIP is to promote the Company’s long-term growth and profitability by providing these individuals with incentives to maximize stockholder value and otherwise contribute to the Company’s success and to enable the Company to attract, retain and reward the best available persons for positions of responsibility. The Compensation Committee of the Board of Directors administers the LTIP. There were 6,798,074 and 7,941,758 shares of common stock remaining available for grants of awards under NRG’s LTIP as of December 31, 2008 and 2007, respectively. The ESPP was approved by the Company’s stockholders on May 14, 2008. There were 500,000 shares reserved from the Company’s treasury shares for the ESPP. There were 500,000 shares remaining under the ESPP as of December 31, 2008. In January 2009, 41,706 shares were issued to employees accounts from the treasury stock reserve for the ESPP. |
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Jan-2004 | Dec-2004 | Dec-2005 | Dec-2006 | Dec-2007 | Dec-2008 | |||||||||||||||||||||||||
NRG Energy, Inc. | $ | 100.00 | $ | 160.58 | $ | 209.89 | $ | 249.49 | $ | 386.10 | $ | 207.84 | ||||||||||||||||||
S&P 500 | 100.00 | 111.22 | 116.68 | 135.11 | 142.53 | 89.80 | ||||||||||||||||||||||||
UTY | $ | 100.00 | $ | 126.23 | $ | 149.50 | $ | 179.67 | $ | 213.76 | $ | 155.45 | ||||||||||||||||||
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Item 6 — | Selected Financial Data |
Year Ended December 31, | ||||||||||||||||||||
2008 | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||
(In millions unless otherwise noted) | ||||||||||||||||||||
Statement of income data: | ||||||||||||||||||||
Total operating revenues | $ | 6,885 | $ | 5,989 | $ | 5,585 | $ | 2,400 | $ | 2,080 | ||||||||||
Total operating costs and expenses | 5,156 | 5,060 | 4,720 | 2,290 | 1,848 | |||||||||||||||
Income from continuing operations, net | 1,016 | 569 | 543 | 68 | 157 | |||||||||||||||
Income from discontinued operations, net | 172 | 17 | 78 | 16 | 29 | |||||||||||||||
Net income | 1,188 | 586 | 621 | 84 | 186 | |||||||||||||||
Common share data: | ||||||||||||||||||||
Basic shares outstanding — average | 235 | 240 | 258 | 169 | 199 | |||||||||||||||
Diluted shares outstanding — average | 275 | 288 | 301 | 171 | 201 | |||||||||||||||
Shares outstanding — end of year | 234 | 237 | 245 | 161 | 174 | |||||||||||||||
Per share data: | ||||||||||||||||||||
Income from continuing operations — basic | 4.09 | 2.14 | 1.90 | 0.28 | 0.78 | |||||||||||||||
Income from continuing operations — diluted | 3.66 | 1.95 | 1.78 | 0.28 | 0.78 | |||||||||||||||
Net income — basic | 4.82 | 2.21 | 2.21 | 0.38 | 0.93 | |||||||||||||||
Net income — diluted | 4.29 | 2.01 | 2.04 | 0.38 | 0.93 | |||||||||||||||
Book value | 26.69 | 19.48 | 19.48 | 11.31 | 13.14 | |||||||||||||||
Business metrics: | ||||||||||||||||||||
Cash flow from operations | $ | 1,434 | $ | 1,517 | $ | 408 | $ | 68 | $ | 645 | ||||||||||
Liquidity position | 4,124 | (a) | 2,715 | 2,227 | 758 | 1,600 | ||||||||||||||
Ratio of earnings to fixed charges | 3.62 | 2.28 | 2.38 | 1.57 | 1.93 | |||||||||||||||
Ratio of earnings to fixed charges and preference dividends | 3.17 | 2.02 | 2.09 | 1.32 | 1.92 | |||||||||||||||
Return on equity | 16.71 | % | 10.65 | % | 10.98 | % | 3.77 | % | 6.91 | % | ||||||||||
Ratio of debt to total capitalization | 47.57 | % | 55.70 | % | 57.38 | % | 44.91 | % | 44.57 | % | ||||||||||
Balance sheet data: | ||||||||||||||||||||
Current assets | $ | 8,492 | $ | 3,562 | $ | 3,083 | $ | 2,197 | $ | 2,119 | ||||||||||
Current liabilities | 6,581 | 2,277 | 2,032 | 1,357 | 1,090 | |||||||||||||||
Property, plant and equipment, net | 11,545 | 11,320 | 11,546 | 2,559 | 2,639 | |||||||||||||||
Total assets | 24,808 | 19,274 | 19,436 | 7,467 | 7,906 | |||||||||||||||
Long-term debt, including current maturities and capital leases | 8,168 | 8,361 | 8,726 | 2,456 | 3,220 | |||||||||||||||
Total stockholders’ equity | $ | 7,109 | $ | 5,504 | $ | 5,658 | $ | 2,231 | $ | 2,692 |
(a) | Includes Funds deposited by counterparties of $754 as of December 31, 2008, which represents cash held as collateral from hedge counterparties in support of energy risk management activities and for which it is the Company’s intention as of December 31, 2008 to limit the use of these funds. |
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Year Ended December 31, | ||||||||||||||||||||
2008 | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Energy | $ | 4,519 | $ | 4,265 | $ | 3,155 | $ | 1,840 | $ | 1,181 | ||||||||||
Capacity | 1,359 | 1,196 | 1,516 | 563 | 612 | |||||||||||||||
Risk management activities | 418 | 4 | 124 | (292 | ) | 61 | ||||||||||||||
Contract amortization | 278 | 242 | 628 | 9 | (6 | ) | ||||||||||||||
Thermal | 114 | 125 | 124 | 124 | 112 | |||||||||||||||
Hedge Reset | — | — | (129 | ) | — | — | ||||||||||||||
Other | 197 | 157 | 167 | 156 | 120 | |||||||||||||||
Total operating revenues | $ | 6,885 | $ | 5,989 | $ | 5,585 | $ | 2,400 | $ | 2,080 | ||||||||||
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Item 7 — | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
• | Factors which affect NRG’s business; | |
• | NRG’s earnings and costs in the periods presented; | |
• | Changes in earnings and costs between periods; | |
• | Impact of these factors on NRG’s overall financial condition; | |
• | A discussion of new and ongoing initiatives that may affect NRG’s future results of operations and financial condition; | |
• | Expected future expenditures for capital projects; and | |
• | Expected sources of cash for future operations and capital expenditures. |
• | Business strategy; | |
• | Business environment in which NRG operates including how regulation, weather, and other factors affect the business; | |
• | Significant events that are important to understanding the results of operations and financial condition; | |
• | Results of operations including an overview of the Company’s results, followed by a more detailed review of those results by operating segment; | |
• | Financial condition addressing its credit ratings, sources and uses of cash, capital resources and requirements, commitments, and off-balance sheet arrangements; and | |
• | Critical accounting policies which are most important to both the portrayal of the Company’s financial condition and results of operations, and which require management’s most difficult, subjective or complex judgment. |
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• | seasonal daily and hourly changes in demand; | |
• | extreme peak demands; | |
• | available supply resources; | |
• | transportation and transmission availability and reliability within and between regions; | |
• | location of NRG’s generating facilities relative to the location of its load-serving opportunities; | |
• | procedures used to maintain the integrity of the physical electricity system during extreme conditions; and | |
• | changes in the nature and extent of federal and state regulations. |
• | weather conditions; | |
• | market liquidity; | |
• | capability and reliability of the physical electricity and gas systems; |
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• | local transportation systems; and | |
• | the nature and extent of electricity deregulation. |
• | Reinvestment in existing assets — Opportunities to invest in the existing business, including maintenance and environmental capital expenditures that improve operational performance, ensure compliance with environmental laws and regulations, and expansion projects. | |
• | Management of debt levels — The Company uses several metrics to measure the efficiency of its capital structure and debt balances, including the Company’s targeted net debt to total capital ratio range of 45% to 60% and certain cash flow and interest coverage ratios. The Company intends in the normal course of business to continue to manage its debt levels towards the lower end of the range and may, from time to time, pay down its debt balances for a variety of reasons. | |
• | Return of capital to shareholders — The Company’s debt instruments include restrictions on the amount of capital that can be returned to shareholders. The Company has in the past returned capital to shareholders while maintaining compliance with existing debt agreements and indentures. The Company expects to regularly return capital to shareholders through opportunistic share repurchases, while exploring other prospects to increase its flexibility under restrictive debt covenants. | |
• | Repowering, econrg and new build opportunities — The Company intends to pursue repowering initiatives that enhance and diversify its portfolio and provide a targeted economic return to the Company. |
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• | Mark-to-market gains— The Company’s risk management activities recognized $414 million in mark-to-market gains driven by lower energy prices due to the downward trend in natural gas prices during the second half 2008. High price volatility in energy related commodities during 2008 drove the extreme volatility reported in NRG interim results of operations and consolidated balance sheets during the second and third quarters of 2008, due to the commodities’ impact on the fair value of our derivative contracts. | |
• | Liquidity Position— The Company’s total liquidity rose $1.4 billion as the declining natural gas prices increased funds deposited by counterparties by $754 million. Cash balances grew by $362 million since the end of 2007 as $1.4 billion of cash provided by operating activities exceeded cash used for all phases of the Company’s Capital Allocation Program, including $899 million of capital expenditures, $185 million in treasury share payments and a $214 million net debt reduction. | |
• | Higher energy prices— Energy revenues rose 6% as a result of strong operating performance at the power plants which allowed the Company to sell generation at higher energy prices especially in the second quarter 2008. | |
• | Higher capacity revenues— Capacity revenues rose $163 million as a result of a greater portion of Texas baseload contracts having a capacity component. | |
• | Sale of ITISA— On April 28, 2008, NRG completed the sale of its interest in a 156 MW hydroelectric power plant to Brookfield Renewable Power Inc. The Company recognized a $164 million after tax gain on the sale and received $300 million of cash proceeds. See Item 15 — Note 3,Discontinued Operations,Business Acquisition and Dispositions,for a further discussion of the activities of ITISA that have been classified as discontinued operations. | |
• | Reduced development costs— As of January 1, 2008, the company began to capitalize the STP units 3 and 4 costs following the docketing of the COLA which resulted in decline of development costs of $52 million. | |
• | Lower other income— Interest income decreased by $25 million as the result of lower market interest rates on cash deposits. In addition, the Company recorded an impairment charge of $23 million to restructure distressed investments in commercial paper. | |
• | Lower interest expense— Interest expense decreased $69 million as the result of the interest savings on the $531 million debt repayments beginning December 2007 accompanied by a reduction of variable interest rates on long-term debt. |
• | NINA— In March 2008, NRG formed NINA, an NRG subsidiary focused on marketing, siting, developing, financing and investing in new advanced design nuclear projects in select markets across North America, including the planned STP units 3 and 4 that NRG is developing on a 50/50 basis with CPS Energy. TANE will serve as the prime contractor on all of NINA’s projects, and has partnered with NRG on the NINA venture, and received a 12% equity ownership in NINA in exchange for a $300 million investment in NINA in six annual installments of $50 million, the first of which was received during 2008 and the last three of which are subject to certain conditions. On February 12, 2009, the Company announced that NINA completed negotiations for the EPC agreement with TANE to build the STP expansion. Concurrent with the execution of the EPC agreement, NINA will enter into a $500 million credit facility with Toshiba to finance the cost of long-lead materials for STP 3 and 4. |
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• | Unsolicited Exelon Proposal— On October 19, 2008, the Company received an unsolicited proposal from Exelon Corporation to acquire all of the outstanding shares of the Company and on November 12, 2008, Exelon announced a tender offer for all of the Company’s outstanding common stock. On January 7, 2009, Exelon extended the tender offer to February 25, 2009, and indicated that further extensions may follow. NRG’s Board of Directors, after carefully reviewing the proposal, unanimously concluded that the proposal was not in the best interests of the stockholders and has recommended that NRG stockholders not tender their shares. In addition, on January 30, 2009 Exelon announced a proposed slate of nine nominees for election to the NRG Board at the 2009 Annual Meeting of Stockholders, together with a proposal to increase the number of NRG directors from 12 to 19. | |
• | Sherbino Wind Farm— On October 22, 2008, NRG and its 50/50 joint venture partner, BP, announced the completion of its 150 MW Sherbino wind farm. Since NRG has a 50 percent ownership, Sherbino will provide the Company a net capacity of 75 MW. | |
• | Elbow Creek Wind Farm— On December 29, 2008, NRG, through Padoma, announced the completion of its Elbow Creek project, a wholly-owned 120 MW wind farm in Howard County near Big Spring, Texas. The Company funded and developed this wind farm which consists of 53 Siemens wind turbine generators, each capable of generating up to 2.3 MW of power. |
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Year Ended | ||||||||||||
December 31, | ||||||||||||
2008 | 2007 | Change% | ||||||||||
(In millions except otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 4,519 | $ | 4,265 | 6 | % | ||||||
Capacity revenue | 1,359 | 1,196 | 14 | |||||||||
Risk management activities | 418 | 4 | N/A | |||||||||
Contract amortization | 278 | 242 | 15 | |||||||||
Thermal revenue | 114 | 125 | (9 | ) | ||||||||
Other revenues | 197 | 157 | 25 | |||||||||
Total operating revenues | 6,885 | 5,989 | 15 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of operations | 3,598 | 3,378 | 7 | |||||||||
Depreciation and amortization | 649 | 658 | (1 | ) | ||||||||
General and administrative | 319 | 309 | 3 | |||||||||
Development costs | 46 | 101 | (54 | ) | ||||||||
Total operating costs and expenses | 4,612 | 4,446 | 4 | |||||||||
Gain on sale of assets | — | 17 | (100 | ) | ||||||||
Operating Income | 2,273 | 1,560 | 46 | |||||||||
Other Income/(Expense) | ||||||||||||
Equity in earnings of unconsolidated affiliates | 59 | 54 | 9 | |||||||||
Gains on sales of equity method investments | — | 1 | (100 | ) | ||||||||
Other income, net | 17 | 55 | (69 | ) | ||||||||
Refinancing expenses | — | (35 | ) | (100 | ) | |||||||
Interest expense | (620 | ) | (689 | ) | (10 | ) | ||||||
Total other expenses | (544 | ) | (614 | ) | (11 | ) | ||||||
Income from Continuing Operations before income tax expense | 1,729 | 946 | 83 | |||||||||
Income tax expense | 713 | 377 | 89 | |||||||||
Income from Continuing Operations | 1,016 | 569 | 79 | |||||||||
Income from discontinued operations, net of income tax expense | 172 | 17 | N/A | |||||||||
Net Income | $ | 1,188 | $ | 586 | 103 | |||||||
Business Metrics | ||||||||||||
Average natural gas price — Henry Hub ($/MMbtu) | 8.85 | 7.12 | 24 | % |
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• | Energy revenues — increased $254 million during the year ended December 31, 2008, compared to the same period in 2007: |
o | Texas— increased $172 million, with $219 million of this increase driven by higher prices, offset by $47 million reduced generation. The price variance was attributable to a more favorable mix of merchant versus contract sales, as well as a 28% increase in merchant prices partially offset by a 14% decrease in contract energy prices. The 839 thousand MWh or 2% reduction in generation was comprised of a 3% reduction from nuclear plant generation, a 14% reduction from gas plant generation, offset by a 1% increase in coal plant generation. The reduction in gas plant generation was attributable to the effects of hurricane Ike in September 2008. | |
o | Northeast— decreased $40 million, with $66 million reduced generation offset by a $26 million increase driven by higher energy prices. The decline due to generation was driven by a net 6% reduction in the region’s generation, due to a decrease in oil-fired generation as a result of higher average oil prices as well as decrease in gas-fired generation related to a cooler summer in 2008 compared to 2007. The increase due to energy prices reflects an average 6% rise in merchant energy prices offset by lower contract revenue, driven by higher costs required to service the PJM contracts, as a result of the increase in market energy prices. | |
o | South Central— increased $74 million, attributable to higher merchant energy revenues. The growth in merchant energy revenues reflected 577 thousand more merchant MWh sold, as a decrease in contract load MWh allowed more sales to the merchant market at higher prices. | |
o | West— increased $35 million due to the dispatch of the El Segundo plant outside of the tolling agreement in 2008. In 2007, no such dispatch occurred. |
• | Capacity revenues— increased $163 million during the year ended December 31, 2008, compared to the same period in 2007: |
o | Texas— increased $130 million due to a greater proportion of base-load contracts, which contain a capacity component. | |
o | Northeast— increased $13 million reflecting $31 million higher capacity revenues in the PJM and NEPOOL markets offset by a $18 million reduction in capacity revenue in NYISO. | |
o | South Central— increased $12 million due to a $10 million higher capacity payment from the region’s cooperative customers and an $8 million rise in RPM capacity payments from the PJM market. These increases were offset by a $6 million reduction related to lower contract volume to other customers. | |
o | West— increased $3 million due to a tolling arrangement at Long Beach plant offset by the reduction of revenue from the El Segundo tolling arrangement. |
• | Contract amortization revenues— increased $36 million during the year ended December 31, 2008, compared to the same period in 2007 due to the volume of contracted energy affected by a greater spread between contract prices and market prices used in the Texas Genco purchase accounting. | |
• | Other revenues— increased by $40 million during the year ended December 31, 2008, compared to the same period in 2007. The increases arose from greater ancillary services revenue of $28 million and increased activity in the trading of emission allowances and carbon financial instruments of $21 million. These increases were offset by $14 million in lower gas and coal trading activities. |
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• | Risk management activities —revenues from risk management activities include economic hedges that did not qualify for cash flow hedge accounting, ineffectiveness on cash flow hedges and trading activities. Such revenues increased by $414 million during the year ended December 31, 2008, compared to the same period in 2007. The breakdown of changes by region was as follows: |
Year Ended December 31, 2008 | ||||||||||||||||||||
Texas | Northeast | South Central | Thermal | Total | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Net (losses)/gains on settled positions, or financial revenues | $ | (95 | ) | $ | 3 | $ | (16 | ) | $ | 1 | $ | (107 | ) | |||||||
Mark-to-market results | ||||||||||||||||||||
Reversal of previously recognized unrealized gains on settled positions related to economic hedges | (25 | ) | (13 | ) | — | — | (38 | ) | ||||||||||||
Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity | 1 | (14 | ) | (19 | ) | — | (32 | ) | ||||||||||||
Net unrealized gains on open positions related to economic hedges | 400 | 96 | — | 4 | 500 | |||||||||||||||
Net unrealized gains on open positions related to trading activity | 37 | 13 | 45 | — | 95 | |||||||||||||||
Subtotal mark-to-market results | 413 | 82 | 26 | 4 | 525 | |||||||||||||||
Total derivative gains | $ | 318 | $ | 85 | $ | 10 | $ | 5 | $ | 418 | ||||||||||
• | Cost of energy— increased $213 million during the year ended December 31, 2008, compared to the same period in 2007 and as a percentage of revenue it decreased from 41% for 2007 as compared to 38% for 2008. This increase was due to : |
o | Texas— Cost of energy increased $59 million due to a net increase in fuel expense and ancillary service costs offset by reductions in nuclear fuel expenses, purchased power expense and amortization of contracts cost. |
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— | Fuel expense— Natural gas costs rose $99 million due to an increase of 28% in average natural gas prices, offset by a 14% decrease in gas-fired generation. In addition, coal costs increased by $44 million a result of higher coal prices and the settlement payment related to a coal contract dispute. These increases were offset by a decrease of $19 million in nuclear fuel expense as amortization of nuclear fuel inventory established under Texas Genco purchase accounting ended in early 2008. | |
— | Purchased energy— Purchased energy expense decreased $26 million as a result of lower forced outage rates at the region’s base-load plants. | |
— | Ancillary service expense— Ancillary services and other costs increased by $14 million as a result of higher ERCOT ISO fees offset by reduced purchased ancillary services costs. | |
— | Fuel contract amortization— Amortized contract costs decreased by $59 million due to a $36 million decrease in the amortization of water supply contracts which ended in 2007. In addition, the amortization of coal contracts decreased by a net $22 million as a result of a reduction in expense related to in-the-money coal contract amortization. These contracts were established under Texas Genco purchase accounting. |
o | Northeast— Cost of energy increased $54 million due to higher fuel costs. Coal costs increased $61 million due to higher coal prices and fuel transportation surcharges. Natural gas costs rose $22 million as a result of 32% higher average natural gas prices, despite 12% lower generation. These increases were offset by a $27 million reduction in oil costs as a result of 55% lower oil-fired generation. | |
o | South Central— Cost of energy increased $56 million due to higher fuel costs and increased purchased energy expense. |
— | Fuel expense— Coal costs increased $16 million resulting from an increase in coal consumption and higher fuel transportation surcharges; natural gas costs rose by $14 million as the region’s peaker plants ran extensively to support transmission system stability after hurricane Gustav. | |
— | Purchased energy— Higher purchased energy expenses of $16 million reflected higher natural gas costs for tolling contracts. | |
— | Transmission costs— Increased by $9 million due to additional point-to-point transmission costs driven by an increase in merchant energy sales. |
o | West— Cost of energy increased $30 million due to the dispatch of the El Segundo plant outside of the tolling agreement in 2008. In 2007, no such dispatch occurred. |
• | Other operating costs —increased $7 million during the year ended December 31, 2008 compared to the same period in 2007. This increase was due to: |
o | Texas— increased $30 million due to a second planned outage at STP and the acceleration of planned outages at the base-load plants. | |
o | Northeast —decreased $3 million due to $18 million lower operating and maintenance expenses resulting from less outage work at the Norwalk plants and Indian River plants. This was offset by a $16 million increase in utilities cost. The 2007 utilities cost included a benefit of $19 million due to a lower than planned settlement of the station service agreement with CL&P. | |
o | South Central —decreased by $10 million due to reduction in major maintenance expense. The 2007 expense included more extensive outage work that was performed at Big Cajun II plant. | |
o | West —decreased by $4 million due to a $3 million reduction in lease expenses and an environmental liability of $2 million which was recognized in 2007 related to the El Segundo plant. |
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• | Wage and benefit costs —increased $19 million attributable to higher wages and related benefits cost increases. | |
• | Consultant cost —increased by $3 million resulting from $8 million spent on Exelon’s exchange offer offset by a $5 million reduction in information technology consultants. | |
• | Franchise tax —The Company’s Louisiana state franchise tax decreased by approximately $4 million. Prior year franchise tax was assessed based on the Company’s total debt and equity that increased significantly following the acquisition of Texas Genco. | |
• | Insurance cost —decreased by $4 million due to favorable rates. |
• | Texas STP units 3 and 4 projects — No development expense was reflected in results of operations for 2008 as NRG began to capitalize STP units 3 and 4 development costs incurred after January 1, 2008, following the NRC’s docketing of the Company’s COLA in late 2007. The Company recorded $52 million in development expenses during 2007. | |
• | Wind projects— The Company incurred $21 million in costs related to wind development which is a $4 million decrease from the same period in 2007. | |
• | Other projects— The Company incurred $25 million in development costs related to other domesticRepoweringNRG projects in 2008, which decreased $7 million from the same period in 2007 as a result of the capitalization of costs to develop the El Segundo Energy Center in 2008. |
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Year Ended | ||||||||
December 31, | ||||||||
2008 | 2007 | |||||||
(In millions | ||||||||
except as otherwise stated) | ||||||||
Income from continuing operations before income taxes | $ | 1,729 | $ | 946 | ||||
Tax at 35% | 605 | 331 | ||||||
State taxes, net of federal benefit | 73 | 46 | ||||||
Foreign operations | (10 | ) | (13 | ) | ||||
Subpart F taxable income | 2 | — | ||||||
Valuation allowance, including change in state effective rate | (12 | ) | 6 | |||||
Change in state effective tax rate | (11 | ) | — | |||||
Change in local German effective tax rates | — | (29 | ) | |||||
Foreign dividends | 32 | 26 | ||||||
Non-deductible interest | 26 | 10 | ||||||
Permanent differences, reserves, other | 8 | — | ||||||
Income tax expense | $ | 713 | $ | 377 | ||||
Effective income tax rate | 41.2 | % | 39.9 | % |
• | Increase in income— pre-tax income increased by $783 million, with a corresponding increase of $305 million in income tax expense. |
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• | Permanent differences— the Company’s effective tax rate differs from the US statutory rate of 35% due to: |
o | Taxable dividends from foreign subsidiaries— due to the provision of deferred taxes in 2008 on foreign income no longer expected to be permanently reinvested overseas offset by decreased dividends from foreign operations in the current year, tax expense increased by approximately $6 million as compared to 2007. | |
o | Non-deductible interest on CAGR Settlement— the Company’s $45 million settlement of the embedded derivative in its CSF I notes and preferred interests resulted in an additional income tax expense of $16 million in 2008 as compared to the same period in 2007. | |
o | Change in German tax rate — as a result of revaluing our deferred tax assets, income tax expense benefited by $29 million in 2007, with no comparable benefit in 2008. | |
o | Valuation Allowance— the Company generated capital gains in 2008 primarily due to the sale of ITISA and derivative contracts that are eligible for capital treatment for tax purposes. These gains enabled NRG to reduce our valuation allowance against capital loss carryforwards. In addition, applicable changes to the state and local effective tax rate are captured in the current period. This resulted in a decrease of $18 million income tax expense in 2008 as compared to 2007. | |
o | Change in state effective tax rate— the Company reduced its domestic state and local deferred income tax rate from 7% to 6% in the current period. |
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Year Ended | ||||||||||||
December 31, | ||||||||||||
2007 | 2006 | Change % | ||||||||||
(In millions | ||||||||||||
except otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 4,265 | $ | 3,155 | 35 | % | ||||||
Capacity revenue | 1,196 | 1,516 | (21 | ) | ||||||||
Risk management activities | 4 | 124 | (97 | ) | ||||||||
Contract amortization | 242 | 628 | (61 | ) | ||||||||
Thermal revenue | 125 | 124 | 1 | |||||||||
Hedge Reset | — | (129 | ) | (100 | ) | |||||||
Other revenues | 157 | 167 | (6 | ) | ||||||||
Total operating revenues | 5,989 | 5,585 | 7 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of operations | 3,378 | 3,265 | 3 | |||||||||
Depreciation and amortization | 658 | 590 | 12 | |||||||||
General and administrative | 309 | 276 | 12 | |||||||||
Development costs | 101 | 36 | 181 | |||||||||
Total operating costs and expenses | 4,446 | 4,167 | 7 | |||||||||
Gain on sale of assets | 17 | — | N/A | |||||||||
Operating Income | 1,560 | 1,418 | 10 | |||||||||
Other Income/(Expense) | ||||||||||||
Equity in earnings of unconsolidated affiliates | 54 | 60 | (10 | ) | ||||||||
Gains on sales of equity method investments | 1 | 8 | (88 | ) | ||||||||
Other income, net | 55 | 156 | (65 | ) | ||||||||
Refinancing expenses | (35 | ) | (187 | ) | (81 | ) | ||||||
Interest expense | (689 | ) | (590 | ) | 17 | |||||||
Total other expenses | (614 | ) | (553 | ) | 11 | |||||||
Income from Continuing Operations before income tax expense | 946 | 865 | 9 | |||||||||
Income tax expense | 377 | 322 | 17 | |||||||||
Income from Continuing Operations | 569 | 543 | 5 | |||||||||
Income from discontinued operations, net of income tax expense | 17 | 78 | (78 | ) | ||||||||
Net Income | $ | 586 | $ | 621 | (6 | ) | ||||||
Business Metrics | ||||||||||||
Average natural gas price — Henry Hub ($/MMbtu) | 7.12 | 6.99 | 2 | % |
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• | Energy revenues— Energy revenues increased by $1.1 billion for the year ended December 31, 2007, compared to 2006: |
o | Texas— energy revenues increased by $972 million, of which $217 million was due to the inclusion of twelve months activity in 2007 compared to eleven months in 2006. Of the remaining $755 million increase, $449 million was due to the Hedge Reset transaction which resulted in higher 2007 average contracted prices of approximately $13 per MWh. In addition, revenues from 8.8 million MWh of generation moved from capacity revenue to energy revenue. Prior to the Acquisition, PUCT regulations required that Texas sell 15% of its capacity by auction at reduced rates. In March 2006, the PUCT accepted NRG’s request to no longer participate in these auctions and that capacity is now being sold in the merchant market. These favorable results were partially offset by lower sales from the region’s natural gas-fired units due to a cooler summer which resulted in lower generation of approximately 2.7 million MWh. | |
o | Northeast— energy revenues increased by approximately $138 million, of which $61 million was due to a 6% increase in generation, primarily driven by increases at the region’s Arthur Kill, Oswego and Indian River plants. The Arthur Kill plant increased generation by 448 thousand MWh due to transmission constraints around New York City, the Oswego plants’ generation increased by 127 thousand MWh due to a colder winter during 2007 compared to 2006, and the Indian River plants’ generation increased by 418 thousand MWh due to stronger pricing and fewer outages in the second half of 2007 compared to the second half of 2006. | |
o | South Central— energy revenues increased by approximately $70 million, due to a new contract which increased contract sales volume by approximately 1.3 million MWh and energy revenues by $69 million. Following a contractual fuel adjustment charge, energy revenues increased by $11 million from the region’s cooperative customers. This was offset by a $12 million decrease in merchant energy revenue. | |
o | West— energy revenues decreased by approximately $72 million, excluding the first quarter 2007, due to the tolling agreement at the Encina plant that has resulted in the receipt of fixed monthly capacity payment in return for the right to schedule and dispatch from the plant. The Encina tolling agreement replaced an RMR agreement under which the plant was called upon to generate and earn energy revenues for such dispatch. |
• | Capacity revenues— Capacity revenues decreased by $320 million for the year ended December 31, 2007, compared to 2006, due to a decrease in Texas capacity revenues that were partially offset by increases in capacity revenues in the Northeast, South Central and West regions: |
o | Texas— capacity revenues decreased by $486 million due to a reduction of capacity auction sales mandated by the PUCT in prior years as previously discussed. | |
o | Northeast— capacity revenues increased by $81 million of which $39 million of the increase was from the region’s NEPOOL assets and $36 million was from the region’s PJM assets. The NEPOOL assets benefited from the new LFRM market and transition capacity market, both introduced in the fourth quarter 2006. Capacity revenues increased by $24 million from the LFRM market and $18 million from transition capacity payments, which was offset by a $3 million reduction in capacity payments due to the expiration of the Devon plant’s RMR agreement on December 31, 2006. On June 1, 2007, the new RPM capacity market became effective in PJM increasing capacity revenues by $36 million as compared to 2006. | |
o | South Central— capacity revenues increased by approximately $22 million. Of this increase, $15 million was due to higher billing rates as a result of the region’s market setting new summer peaks hit in 2006 and 2007, $6 million was due to higher contractual transmission pass-though costs to the region’s cooperative customers and $3 million was due to improved market conditions at the region’s Rockford plants. In |
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August 2007, the region set a new system peak of 2,123 MW which will continue to impact capacity revenue in the first half of 2008. |
o | West— capacity revenues increased by approximately $54 million, of which $26 million was related to the inclusion of the first quarter 2007 compared to 2006. New tolling agreements at the region’s Encina and Long Beach plants accounted for the remaining difference, with the Encina facility contributing approximately $15 million and the newly-repowered Long Beach facility contributing approximately $13 million. |
• | Contract amortization— revenues from contract amortization decreased by $386 million for the year ended December 31, 2007, compared to 2006, as a result of the November 2006 Hedge Reset transaction, which resulted in a write-off of a large portion of the Company’s out-of-market power contracts during the fourth quarter 2006. | |
• | Other revenues —Other revenues decreased by $10 million for the year ended December 31, 2007, compared to 2006 due to: |
o | Sale of emission allowances — net sales of SO2 emission allowances decreased by approximately $33 million. In 2006, we sold emissions in lieu of generation due to an unseasonably warm first quarter. Since that time the average market price for SO2 allowances decreased by 28%. | |
o | Physical gas sales— decreased by $7 million due to the lower sales of excess natural gas. | |
o | Ancillary revenues— Ancillary services revenue increased by approximately $27 million due to a change in strategy to actively provide ancillary services in the Texas region which increased revenues by $33 million. This was partially offset by a $4 million reduction in ancillary services in the Northeast region due to higher transmission costs following transmission constraints in the New York City area. |
• | Risk management activities —Gains/losses from risk management activities include economic hedges that do not qualify for hedge accounting, ineffectiveness on cash flow hedges, and trading activities. Such gains were $4 million for the year ended December 31, 2007. The breakdown of changes by region are as follows: |
Year Ended December 31, 2007 | ||||||||||||||||
South | ||||||||||||||||
Texas | Northeast | Central | Total | |||||||||||||
(In millions) | ||||||||||||||||
Net gains on settled positions, or financial revenues | $ | 33 | $ | 43 | $ | 5 | $ | 81 | ||||||||
Mark-to-market results | ||||||||||||||||
Reversal of previously recognized unrealized gains on settled positions related to economic hedges | (83 | ) | (45 | ) | — | (128 | ) | |||||||||
Reversal of previously recognized unrealized gains on settled positions related to trading activity | (1 | ) | (12 | ) | (19 | ) | (32 | ) | ||||||||
Net unrealized gains on open positions related to economic hedges | 19 | 15 | — | 34 | ||||||||||||
Net unrealized (losses)/gains on open positions related to trading activity | (1 | ) | 26 | 24 | 49 | |||||||||||
Subtotal mark-to-market results | (66 | ) | (16 | ) | 5 | (77 | ) | |||||||||
Total derivative (losses)/gains | $ | (33 | ) | $ | 27 | $ | 10 | $ | 4 | |||||||
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• | Cost of energy —Cost of energy decreased by approximately $24 million, to $2,428 million, for the year ended December 31, 2007, compared to 2006, and as a percentage of revenue it decreased from 44% for the year ended December 31, 2006, to 41% for the year ended December 31, 2007. This decrease was due to: |
o | Texas —cost of energy decreased by $95 million for the year ended December 31, 2007, compared to 2006. This decrease included an additional month’s expense of $96 million in 2007, without which cost of energy would have decreased by $191 million. This decrease was due to a reduction in natural gas expense and fuel contract amortization, partially offset by increased ancillary service expense. |
— | Fuel expense and purchased power expense— Natural gas expense decreased by $170 million, which excludes January 2007 natural gas expense of $27 million. This decrease was due to a reduction of 2.7 million MWh in gas-fired generation as a result of cooler summer weather, coupled with greater economic purchases from the ERCOT and increased baseload generation. Despite higher coal-fired generation at the region’s W.A. Parish and Limestone plants, the region’s coal expenses, excluding January 2007, decreased by $13 million due to a 9% reduction in average contracted coal prices. | |
— | Fuel contract amortization— decreased by approximately $43 million, excluding January 2007, due to declining forward fuel price curves below the contracted prices used at the Acquisition. | |
— | Purchased ancillary service expense— increased by approximately $34 million due to favorable market prices in purchasing this service in the market compared to providing the service from internal resources. |
o | Northeast— cost of energy increased by $26 million primarily due to $30 million in higher natural gas costs related to increased generation at the region’s Arthur Kill plant due to its locational advantage to New York City following transmission constraints during the last three quarters of 2007. | |
o | South Central— cost of energy increased by $104 million due to increases in purchased energy, coal costs and transmission costs. |
— | Purchased energy— increased by approximately $69 million due to increased market purchases following increased cooperative load requirements and planned maintenance at the region’s Big Cajun II facility. | |
— | Coal costs— increased by approximately $17 million, of which $11 million was related to a 9% increase in coal prices and $7 million due to higher coal transportation costs. | |
— | Transmission costs— increased by approximately $16 million of which $6 million was due to contractual increases related to network transmission service. Point-to-point transmission costs also increased by $10 million reflecting more off-system sales. |
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o | West— Cost of energy decreased by approximately $76 million, excluding the first quarter 2007, due to new tolling agreement entered into at the Encina plant in 2007, which requires the counterparty to supply their own fuel. Under the previous arrangement in 2006, the plant supplied the fuel. |
• | Other operating costs —Other operating costs which include operations and maintenance expenses, or O&M, increased by $137 million, to $950 million, for the year ended December 31, 2007, compared to 2006. This increase was due to: |
o | Texas— other operating costs increased by $75 million, after excluding January 2007 expense of $39 million, other operating costs increased by $36 million. This $36 million increase was due to $25 million in higher O&M expense as a result of increased maintenance associated with planned outages and fuel handling at the W.A. Parish facility and $10 million in higher property tax expenses following an increased valuation after the Acquisition. | |
o | Northeast— other operating costs increased by $18 million due to increased staffing costs and higher maintenance costs. | |
o | South Central —other operating costs increased by approximately $28 million, $19 million of which was due to increased maintenance expense primarily related to planned outages. Additionally, the region disposed of $4 million in assets in conjunction with the outage. | |
o | Acquisition of WCP —these results include $15 million of WCP expenses that were not included in the Company’s results in 2006. |
• | Texas acquisition —the inclusion of Texas results for twelve months in 2007 compared to eleven months in 2006 resulted in an increase of approximately $38 million. | |
• | Impact of new environmental legislation —due to new and more restrictive environmental legislation, the useful life of certain pollution control equipment has been reduced. The Company accelerated depreciation on certain equipment in its Northeast region to reflect the remaining useful life, resulting in increased depreciation of approximately $13 million. |
• | Texas and WCP acquisitions —the inclusion of Texas results for twelve months in 2007 compared to eleven months in 2006 and the consolidation of WCP for the last three quarters of 2006 resulted in an increase of approximately $9 million. | |
• | Wage and benefit costs —due to the expansion of the Company, includingRepoweringNRG initiatives, wages and related benefits costs resulted in a $28 million increase in G&A. Additionally, information technology and other office services to support this expansion increased by $8 million. | |
• | Franchise tax —the Company’s Louisiana state franchise tax increased by approximately $6 million. This increase was because the state’s franchise tax was assessed based on the Company’s total debt and equity that rose significantly following the acquisition of Texas Genco. | |
• | Non-recurring expenses during 2006 —for the year ended December 31, 2006, G&A included non-recurring fees of $20 million of which $6 million were related to the unsolicited takeover attempt by Mirant Corporation and $14 million associated with the Texas integration efforts. |
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• | Texas —on September 24, 2007, NRG filed a COLA with the NRC to build and operate two new nuclear units at the STP site. During the period, NRG incurred $91 million in development costs related to STP units 3 and 4 project in 2007. These development costs were reduced by a $39 million reimbursement related to a partnership agreement signed during the fourth quarter 2007. | |
• | Wind projects —approximately $13 million in development costs related to wind projects primarily in Texas. | |
• | Other project —approximately $4 million in development costs related to otherRepoweringNRG projects in the West region. |
• | Refinancing for the acquisition of Texas Genco in February 2006 — the Company significantly increased its corporate debt facilities from approximately $2 billion as of December 31, 2005, to approximately $7 billion as of February 2, 2006. This increased interest expense by approximately $12 million compared to 2006. | |
• | Increase of $1.1 billion in debt for Hedge Reset —the Company issued $1.1 billion in Senior Notes due 2017 in November 2006 related to the Hedge Reset, which increased interest expense by approximately $72 million. |
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• | Capital Allocation Program —the Company issued a total of $330 million of debt to fund Phase I of the Capital Allocation Program during the second half of 2006. This increased interest expense by $20 million compared to 2006. |
Year Ended December 31, | ||||||||
2007 | 2006 | |||||||
(In millions | ||||||||
except otherwise stated) | ||||||||
Income from continuing operations before income taxes | $ | 946 | $ | 865 | ||||
Tax at 35% | 331 | 303 | ||||||
State taxes, net of federal benefit | 46 | 34 | ||||||
Foreign operations | (13 | ) | (21 | ) | ||||
Subpart F taxable income | — | 11 | ||||||
Valuation allowance, including change in state effective rate | 6 | (10 | ) | |||||
Change in state effective tax rate | — | 21 | ||||||
Claimant reserve settlements | — | (28 | ) | |||||
Change in local German effective tax rates | (29 | ) | — | |||||
Foreign dividends | 26 | 1 | ||||||
Non-deductible interest | 10 | 3 | ||||||
Permanent differences, reserves, other | — | 8 | ||||||
Income tax expense | $ | 377 | $ | 322 | ||||
Effective income tax rate | 39.9 | % | 37.2 | % |
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• | Increase in profits —income before tax increased by $81 million, with a corresponding increase of approximately $32 million in income tax expense. | |
• | Permanent differences —the Company’s effective tax rate differs from the US statutory rate of 35% due to: |
o | Change in German tax rate— due to a reduction in the German statutory and resulting effective tax rate, income tax expense benefited by $29 million for the year-ended 2007. | |
o | Taxable dividends from foreign subsidiaries— in January 2007, the Company transferred the proceeds from the sale of its Flinders assets to the US creating additional income tax expense of approximately $25 million. | |
o | Lower tax rates in foreign jurisdictions— lower income tax rates at the Company’s foreign locations resulted in additional income tax expense during 2007 compared to 2006 of $8 million. | |
o | Non-deductible interest— interest expense from the stock buybacks from Phase I of the Company’s Capital Allocation Program was non-deductible for income tax purposes, thus increasing income tax expense by approximately $7 million. | |
o | Change in state effective tax rate— the state effective tax rate remained unchanged for 2007. This resulted in a net decrease in income tax expense of approximately $5 million as compared to 2006, after taking into account the movement in valuation allowance as a result of the change in rate from 2005 to 2006. | |
o | Subpart F taxable income— a dividend was declared and paid in 2007 by NRGenerating International B.V. As result of this dividend, there was no Subpart F income compared to 2006. This resulted in a decrease to income tax expense of approximately $11 million. | |
o | Disputed claims reserve— During 2007 as compared to 2006, the Company made no distribution from its disputed claims reserve, this increased income tax expense by approximately $28 million. |
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Year Ended | ||||||||||||
December 31, | ||||||||||||
2008 | 2007 | Change % | ||||||||||
(In millions except | ||||||||||||
otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 2,870 | $ | 2,698 | 6 | % | ||||||
Capacity revenue | 493 | 363 | 36 | |||||||||
Risk management activities | 318 | (33 | ) | N/A | ||||||||
Contract amortization | 255 | 219 | 16 | |||||||||
Other revenues | 90 | 40 | 125 | |||||||||
Total operating revenues | 4,026 | 3,287 | 22 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of energy | 1,240 | 1,181 | 5 | |||||||||
Depreciation and amortization | 451 | 469 | (4 | ) | ||||||||
Other operating expenses | 650 | 668 | (3 | ) | ||||||||
Operating Income | $ | 1,685 | $ | 969 | 74 | |||||||
MWh sold (in thousands) | 47,806 | 49,220 | (3 | ) | ||||||||
MWh generated (in thousands) | 46,937 | 47,779 | (2 | ) | ||||||||
Business Metrics | ||||||||||||
Average on-peak market power prices ($/MWh) | $ | 96.53 | $ | 62.00 | 56 | |||||||
Cooling Degree Days, or CDDs(a) | 2,719 | 2,707 | — | |||||||||
CDD’s 30 year rolling average | 2,647 | 2,647 | — | |||||||||
Heating Degree Days, or HDDs(a) | 1,961 | 1,949 | 1 | |||||||||
HDD’s 30 year rolling average | 2,007 | 1,997 | 1 | % |
(a) | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
• | Energy revenues— increased by $172 million due to higher merchant energy revenue as a result of higher power prices and sales volumes offset by lower contract energy revenue. | |
• | Capacity revenue— increased by $130 million due to a greater proportion of base-load contracts which contain a capacity component. | |
• | Risk management activities— an increase of $351 million was primarily due to $479 million in greater unrealized derivative gains offset by $128 million in greater realized losses on settled financial transactions. These changes reflect a reduction in forward power and gas prices at the close of the year ended December 31, 2008. |
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• | Cost of energy— increased by $59 million reflecting the effects of increased natural gas and coal prices. |
• | Risk management activities— gains of $318 million were recognized for the year ended December 31, 2008, compared to a $33 million loss in the same period in 2007. The $318 million included $413 million of unrealized mark-to-market gains and $95 million in settled losses, or financial revenue. The $413 million was the net effect of a $400 million gain from economic hedge positions and a $25 million loss on reversals of mark-to-market gains on economic hedges. In addition, there were $37 million in unrealized mark-to-market gains on trading transactions combined with a $1 million gain on reversals of mark-to-market losses on trading activity. The $400 million gain from economic hedges incorporated $424 million in unrealized gains in the value of forward sales of electricity and fuel driven by lower power and natural gas prices. These hedges were considered effective economic hedges that do not receive cash flow hedge accounting treatment. The remaining $24 million in losses were from hedge ineffectiveness which was driven by decreasing gas prices while power prices decreased at a slower pace. | |
• | Energy revenues— increased by $172 million due to: |
o | Energy prices —increased by $219 million due to a more favorable mix of merchant versus contract sales resulting in a 28% increase in merchant prices offset by a 14% decrease in contract energy prices. | |
o | Generation —decreased by 839 thousand MWh or 2%. This decrease in generation was due to a 3% decline in nuclear generation at STP, as a result of additional plant outages, and a 14% decline in overall gas plant generation for the year ended December 2008. Hurricane Ike in September 2008 caused major damage to the Houston area transmission grid which reduced significantly the demand for power causing a decrease in gas-fired generation. These declines were offset by a 1% increase in coal generation in 2008. |
• | Capacity revenue— increased by $130 million due to a greater proportion of base-load contracts which contain a capacity component. | |
• | Other revenues —increased by $50 million related to a $23 million increase in ancillary services revenue in 2008, a $22 million increase of allocations for trading of emission allowances and carbon financial instruments, and increased activity in trading natural gas and coal of $4 million. | |
• | Contract amortization revenue— increased by $36 million due to the volume of contracted energy being positively affected by a greater spread between contract prices and market prices used in the Texas Genco purchase accounting. |
• | Natural gas costs— increased by $99 million due to a 28% rise in average gas prices offset by a 14% decrease in gas-fired generation. | |
• | Coal costs— increased by $44 million due to higher coal prices and the settlement of a coal contract dispute. | |
• | Ancillary services— increased by $14 million due to a $16 million rise in ancillary service costs purchased through ERCOT, offset by a $2 million decrease in other purchased ancillary services costs. |
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• | Amortized contract costs— decreased by $59 million due to a $36 million decrease in the amortization of water supply contracts which ended in 2007. In addition, the amortization of coal contracts decreased by a net $22 million as a result of a reduction in expense related to in-the-money coal contract amortization. These contracts were established under Texas Genco purchase accounting. | |
• | Nuclear fuel expense— decreased by $19 million as amortization of nuclear fuel inventory established under Texas Genco purchase accounting ended in early 2008. | |
• | Purchased power— decreased by $26 million due to lower forced outage rates at the region’s baseload plants. |
• | Development costs— decreased by $59 million primarily due to the initial costs for developing the nuclear units 3 and 4 at STP associated with theRepoweringNRG initiative that began in 2007. Costs for STP nuclear units 3 and 4 are being capitalized in 2008. |
• | Operations & maintenance expense— increased by $32 million due to an additional planned outage at STP and the acceleration of planned outages at the baseload plants. | |
• | General and Administrative expense— increased by $10 million driven by higher corporate allocations. |
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Year Ended | ||||||||||||
December 31, | ||||||||||||
2007 | 2006(b) | Change % | ||||||||||
(In millions except | ||||||||||||
otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 2,698 | $ | 1,726 | 56 | % | ||||||
Capacity revenue | 363 | 849 | (57 | ) | ||||||||
Risk management activities | (33 | ) | (30 | ) | 10 | |||||||
Contract amortization | 219 | 609 | (64 | ) | ||||||||
Hedge Reset | — | (129 | ) | (100 | ) | |||||||
Other revenues | 40 | 63 | (37 | ) | ||||||||
Total operating revenues | 3,287 | 3,088 | 6 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of energy | 1,181 | 1,276 | (7 | ) | ||||||||
Depreciation and amortization | 469 | 413 | 14 | |||||||||
Other operating expenses | 668 | 518 | 29 | |||||||||
Operating Income | $ | 969 | $ | 881 | 10 | |||||||
MWh sold (in thousands) | 49,220 | 46,361 | 6 | |||||||||
MWh generated (in thousands) | 47,779 | 44,910 | 6 | |||||||||
Business Metrics | ||||||||||||
Average on-peak market power prices ($/MWh) | $ | 62.00 | $ | 63.07 | (2 | ) | ||||||
Cooling Degree Days, or CDDs(a) | 2,707 | 3,108 | (13 | ) | ||||||||
CDD’s 30 year rolling average | 2,647 | 2,647 | — | |||||||||
Heating Degree Days, or HDDs(a) | 1,949 | 1,533 | 27 | % | ||||||||
HDD’s 30 year rolling average | 1,997 | 1,997 | — |
(a) | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. | |
(b) | For the period February 2, 2006 to December 31, 2006 only. |
• | Energy Revenues— for eleven months of 2007 compared to the same period in 2006 were up by $755 million, $449 million of which was due to the Hedge Reset transaction, as the average price of the underlying power contracts increased by $13 per MWh compared to average contract prices prior to the hedge reset. The balance of the increase in energy revenues was due to the sale of additional output as energy rather than under PUCT mandated capacity auctions. |
• | Capacity Revenues— reduction in capacity auction sales reduced capacity revenues by approximately $517 million, excluding January 2007. |
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• | Contract Amortization— the Hedge Reset transaction decreased contract amortization by approximately $498 million, excluding January 2007. | |
• | Gas-fired Generation —lower natural gas-fired generation of approximately 2.7 million MWh, for the comparable eleven month period in 2007, was a result of cooler summer weather coupled with increased economic purchases of energy and ancillary services from the ERCOT. Lower sales revenue for the eleven months was offset by natural lower natural gas fuel costs of $170 million and cash flow economic hedge improvements. | |
• | Development Costs— increased by $44 million in 2007 compared to 2006 largely due to the development of STP nuclear units 3 and 4 project, including $2 million of expenses in January 2007. The $44 million increase also includes $39 million in reimbursements from a partnership agreement signed in the fourth quarter 2007. |
• | Energy revenues— energy revenues increased by $972 million, of which $217 million was due to the inclusion of twelve months activity in 2007 compared to eleven months in 2006. Of the remaining $755 million increase, $449 million was due to the Hedge Reset transaction which resulted in higher 2007 average contracted prices of approximately $13 per MWh. In addition, revenues from 8.8 million MWh of generation moved from capacity revenue to energy revenue. Prior to the Acquisition, PUCT regulations required that NRG Texas sell 15% of its capacity by auction at reduced rates. In March 2006, the PUCT accepted NRG’s request to no longer participate in these auctions and that capacity is now being sold in the merchant market. These favorable results were partially offset by lower sales from natural gas-fired units due to a cooler summer which resulted in lower natural gas-fired generation of approximately 2.7 million MWh. | |
• | Other revenues— the region’s other revenues decreased by $27 million for the eleven months of 2007 compared to 2006. This was due to a decrease in intercompany emission allowance sales of $40 million and a $19 million decrease in physical gas sales. This $59 million decrease was offset by a $33 million increase in ancillary services revenue due to a change in strategy to more actively provide ancillary services in the Texas region. | |
• | Capacity revenues— capacity revenues decreased by $517 million, excluding $31 million incurred in January 2007. This decrease was due to the reduction of capacity auction sales mandated by the PUCT in prior years as described above. | |
• | Contract amortization— revenues from contract amortization excluding January 2007 decreased by $405 million primarily due to the write-off of out-of-market power contracts during the fourth quarter 2006 related to the Hedge Reset transaction. | |
• | Risk management activities— The Texas region recorded a total of $33 million in derivative losses for the year ended December 31, 2007, compared to a $30 million loss for the year ended December 31, 2006. The Texas region’s 2007 derivative loss was comprised of $66 million of mark-to-market losses and $33 million in settled gains, or financial revenue. Of the $66 million of mark-to-market losses, $83 million represents the reversal of mark-to-market gains previously recognized on economic hedges and $1 million from the reversal of mark-to-market gains previously recognized on trading activity. Both of these losses ultimately settled as financial revenues during 2007. The $19 million gain from economic hedge positions was comprised of an $8 million increase in the value of forward sales of electricity and fuel due to favorable power and natural gas prices and a $11 million gain from hedge accounting ineffectiveness. This ineffectiveness was primarily related to gas swaps and collars due to a change in the correlation between natural gas and power prices. |
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• | Fuel expense — natural gas expense decreased by $170 million, excluding the January 2007 expense of $27 million, due to a decrease of 2.7 million MWh in natural gas-fired generation as a result of cooler summer weather, coupled with greater economic purchases of energy and ancillary services from the ERCOT and increased baseload generation. Coal expenses, excluding January 2007, decreased by $13 million due to a 9% reduction in average contracted coal prices in 2007, despite a 1.1 million MWh increase in coal-fired generation at the region’s W.A. Parish and Limestone plants. | |
• | Purchased ancillary service— increased by approximately $34 million due to the favorable market prices in purchasing this service in the market compared to providing the service from internal resources causing an associated decrease in natural gas expense. | |
• | Fuel contract amortization— decreased by approximately $43 million, excluding January 2007, due to declining forward fuel price curves below the contracted prices used at acquisition in February 2006. |
• | Development costs— on September 24, 2007, NRG filed a COLA with the NRC. The Company incurred $91 million in development costs related to STP nuclear unit 3 and 4 project in 2007, including $2 million in January 2007, compared to development costs of $14 million in 2006. Of the $91 million incurred this year, $39 million was reimbursed through a partnership agreement in the fourth quarter 2007. Fossil development costs were $6 million in 2007. | |
• | Plant O&M expense— increased by $25 million, excluding January 2007, due to increased maintenance associated with planned outages and fuel handling at W.A. Parish, increased maintenance related to higher utilization in 2006 of the region’s natural gas fleet, and retirement of older assets. | |
• | Corporate allocations— were higher by approximately $16 million. | |
• | Property tax expense— increased by approximately $10 million related to the Texas acquisition. |
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Year Ended | ||||||||||||
December 31, | ||||||||||||
2008 | 2007 | Change % | ||||||||||
(In millions except | ||||||||||||
otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 1,064 | $ | 1,104 | (4 | )% | ||||||
Capacity revenue | 415 | 402 | 3 | |||||||||
Risk management activities | 85 | 27 | 215 | |||||||||
Other revenues | 66 | 72 | (8 | ) | ||||||||
Total operating revenues | 1,630 | 1,605 | 2 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of energy | 695 | 641 | 8 | |||||||||
Depreciation and amortization | 109 | 102 | 7 | |||||||||
Other operating expenses | 392 | 404 | (3 | ) | ||||||||
Operating Income | $ | 434 | $ | 458 | (5 | ) | ||||||
MWh sold (in thousands) | 13,349 | 14,163 | (6 | ) | ||||||||
MWh generated (in thousands) | 13,349 | 14,163 | (6 | ) | ||||||||
Business Metrics | ||||||||||||
Average on-peak market power prices ($/MWh) | $ | 91.70 | $ | 76.37 | 20 | |||||||
Cooling Degree Days, or CDDs(a) | 611 | 702 | (13 | ) | ||||||||
CDD’s 30 year rolling average | 537 | 537 | — | |||||||||
Heating Degree Days, or HDDs(a) | 6,057 | 6,074 | — | |||||||||
HDD’s 30 year rolling average | 6,294 | 6,261 | 1 | % |
(a) | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
• | Cost of energy— increased by $54 million due to higher coal costs, increased coal transportation surcharges and higher natural gas prices. The increase was offset by lower oil costs from lower oil-fired generation. |
• | Operating revenues —increased by $25 million due to higher capacity revenue and risk management revenues partially offset by lower energy revenue. | |
• | Other operating expenses— decreased by $12 million due to lower major maintenance expenses and property taxes offset by higher utilities expense. |
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• | Risk management activities— gains of $85 million were recorded for the year ended December 31, 2008, compared to gains of $27 million during the same period in 2007. The $85 million gain includes $82 million of unrealized mark-to-market gains and $3 million of gains in settled transactions, or financial revenue. The $82 million unrealized gains is the net effect of a $96 million gain from economic hedge positions, the $13 million loss due to the reversal of previously recognized mark-to-market gains on economic hedges, the $14 million loss due to the reversal of mark-to-market gains on trading activity and $13 million in unrealized mark-to-market gains on trading activity. Gains are driven by increases in power and gas prices. | |
• | Capacity revenues— increased by $13 million due to: |
o | PJM— capacity revenues increased by $20 million reflecting recognition of a year of revenue from the RPM capacity market (effective on June 1, 2007) in 2008 compared to seven months in 2007. | |
o | NEPOOL— capacity revenues increased $11 million due to increased revenue recognized on the Norwalk RMR contract (effective on June 19, 2007) in 2008 compared to seven months in 2007. | |
o | NYISO— capacity revenues decreased by $18 million due to unfavorable market prices. The lower capacity market prices are a result of NYISO’s reductions in Installed Reserve Margins and ICAP in-city mitigation rules effective March 2008. These decreases were offset by higher capacity contract revenue. |
• | Energy revenues —decreased by $40 million due to: |
o | Energy prices— increased by a net $26 million. An average 6% rise in merchant energy prices resulted in an increase of $64 million. This increase was offset by lower contract revenue of $38 million driven by higher net costs incurred to service PJM contracts as a result of the increase in market energy prices. | |
o | Generation— decreased by $66 million due to a net 6% decrease in generation. The decrease in generation represented a 55% decrease in oil-fired generation as these oil-fired plants were not dispatched due to 41% higher average oil prices. In addition, there was a 12% decrease in gas-fired generation related to a cooler summer in 2008 as compared to 2007. Coal generation was flat in 2008 compared to 2007. |
• | Other revenues— decreased by $6 million due to lower allocations of net physical sales in 2008 of $17 million offset by higher allocations for trading of emission allowances and carbon financial instruments of $10 million. |
• | Coal costs— increased by $61 million due to higher coal costs and fuel transportation surcharges. | |
• | Natural gas costs— increased by $22 million, despite 12% lower generation, due to a 32% higher average natural gas prices. |
• | Oil costs— decreased by $27 million due to lower oil-fired generation of 55% as these plants were not dispatched in 2008 due to 41% higher average oil prices. |
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• | Major Maintenance— decreased $18 million as a result of less outage work at the Norwalk and Indian River plants. | |
• | Property taxes— decreased $10 million due to $4 million in property tax credits received in 2008 at our New York City plants and higher property credits received in 2008 at our Western New York plants. |
• | Utilities expense— increased by $16 million as a result of a $19 million benefit included in the 2007 utilities cost due to a lower than planned settlement of the station service agreement with CL&P. |
Year Ended | ||||||||||||
December 31, | ||||||||||||
2007 | 2006 | Change % | ||||||||||
(In millions except otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 1,104 | $ | 966 | 14 | % | ||||||
Capacity revenue | 402 | 321 | 25 | |||||||||
Risk management activities | 27 | 144 | (81 | ) | ||||||||
Other revenues | 72 | 112 | (36 | ) | ||||||||
Total operating revenues | 1,605 | 1,543 | 4 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of energy | 641 | 615 | 4 | |||||||||
Depreciation and amortization | 102 | 89 | 15 | |||||||||
Other operating expenses | 404 | 378 | 7 | |||||||||
Operating Income | $ | 458 | $ | 461 | (1 | ) | ||||||
MWh sold (in thousands) | 14,163 | 13,309 | 6 | |||||||||
MWh generated (in thousands) | 14,163 | 13,309 | 6 | |||||||||
Business Metrics | ||||||||||||
Average on-peak market power prices ($/MWh) | $ | 76.37 | $ | 67.73 | 13 | |||||||
Cooling Degree Days, or CDDs(a) | 702 | 653 | 8 | |||||||||
CDD’s 30 year rolling average | 537 | 537 | — | |||||||||
Heating Degree Days, or HDDs(a) | 6,074 | 5,417 | 12 | % | ||||||||
HDD’s 30 year rolling average | 6,261 | 6,261 | — |
(a) | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
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• | Cost of energy— increased by approximately $26 million due to a 6% increase in generation at the region’s coal and natural gas-fired plants. | |
• | Other operating expenses— increased by $26 million primarily due to increased maintenance and staffing costs combined with higher property tax. | |
• | Depreciation— increased by $13 million reflecting the additional depreciation expense following the reduction in estimated useful lives of certain components of the region’s power plants as a result of new environmental regulation. | |
• | Offset by higher operating revenues— of approximately $62 million due to increased generation, favorable pricing and the favorable impact from new capacity markets. This was partially offset by lower gains in the region’s risk management activities and lower sales of emission allowances due to a 28% reduction in market prices. |
• | Energy revenues —increased by approximately $138 million, of which $61 million was due to increased generation, and $88 million due to a 9% increase in average realized market prices partially offset by an $11 million reduction in contracted bilateral energy revenues. |
o | Generation— increased by 6%, primarily driven by increases at the region’s Arthur Kill, Oswego and Indian River plants. The Arthur Kill plant increased generation by 448 thousand MWh due to transmission constraints around New York City, the Oswego plants’ generation increased by 127 thousand MWh due to a colder winter during 2007 compared to 2006, and Indian River plants’ generation increased by 418 thousand MWh due to stronger pricing and fewer outages. | |
o | Price— on average, realized prices in the Northeast increased by 9% due to a mix of higher priced New York City generation coupled with improved economic energy hedge trading resulting in a $37 million increase in energy revenues. |
• | Capacity revenues— increased by $81 million, of which $39 million was from the region’s NEPOOL assets, $36 million from the region’s PJM assets and $6 million from the region’s New York Rest of State assets. |
o | NEPOOL— The region’s NEPOOL assets benefited from the new LFRM market and transition capacity market, both of which were introduced in the fourth quarter 2006. Capacity revenues increased by $24 million from the LFRM market and $18 million from transition capacity payments, which were partially offset by a $3 million reduction due to the expiration of an RMR agreement for the region’s Devon plant on December 31, 2006 and by RMR payments from the region’s Norwalk plant which began in the third quarter 2007. | |
o | PJM— On June 1, 2007, the new RPM capacity market became effective in PJM increasing capacity revenues by approximately $36 million. | |
o | NYISO— New York Rest of State capacity prices increased by 75% as load requirement growth increased demand for capacity. This was coupled with the impact from the new capacity markets in NEPOOL which reduced exported supply into the New York market that further improved the supply/demand dynamics. |
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• | Risk management activities— The Northeast region recorded $27 million in derivative gain for the year ended December 31, 2007 compared to a $144 million gain for the year ended December 31, 2006. The region’s 2007 derivative gain was comprised of $16 million of mark-to-market losses and $43 million in settled gains, or financial revenue. Of the $16 million of mark-to-market losses, $45 million represents the reversal of mark-to-market gains previously recognized on economic hedges and $12 million from the reversal of mark-to-market gains previously recognized on trading activity. Both of these losses ultimately settled as financial revenues during 2007. The region also recognized a $15 million unrealized gain from economic hedge positions which was comprised primarily of a $13 million increase in the value of forward sales of electricity and fuel due to favorable power and gas prices. The region also recognized a $26 million unrealized gain associated with the Company’s trading activity. The $144 million derivative gain for the year ended December 31, 2006 was comprised of a $154 million unrealized mark-to-market gain and $10 million in settled losses. Most of these unrealized gains reversed out in 2007. | |
• | Other revenues— decreased by $40 million, of which approximately $48 million was due to reduced activity in the trading of emission allowances following both an increase in generation and a 28% decrease in market prices. This decrease was partially offset by an $11 million increase in physical gas sales to third parties due to favorable trading opportunities in the market. |
• | Cost of energy increased by $26 million for the year ended December 31, 2007, compared to 2006, primarily due to $30 million in higher natural gas costs related to increased generation at the region’s Arthur Kill plant due to its locational advantage to New York City following transmission constraints during the last three quarters of 2007. |
• | Plant O&M spending— of $15 million due to increased plant staffing costs of $7 million, increased maintenance costs of $6 million and increased environmental remediation costs of $2 million. | |
• | Property tax— increased by approximately $3 million due to a favorable tax decision in 2006 related to NYC assets of $10 million partially offset by a tax law change the same year that resulted in a reduction of property tax receivable of $5 million in 2006 and a $2 million reduction in property taxes at the New England plants in 2007. | |
• | Regional G&A expenditures— Regional staffing and benefits increased by $3 million primarily related to the region’sRepoweringNRG development efforts while corporate allocations increased by $5 million. |
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Year Ended | ||||||||||||
December 31, | ||||||||||||
2008 | 2007 | Change % | ||||||||||
(In millions except otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 478 | $ | 404 | 18 | % | ||||||
Capacity revenue | 233 | 221 | 5 | |||||||||
Risk management activities | 10 | 10 | — | |||||||||
Contract amortization | 23 | 23 | — | |||||||||
Other revenues | 2 | — | N/A | |||||||||
Total operating revenues | 746 | 658 | 13 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of energy | 468 | 412 | 14 | |||||||||
Depreciation and amortization | 67 | 68 | (1 | ) | ||||||||
Other operating expenses | 111 | 121 | (8 | ) | ||||||||
Operating Income | $ | 100 | $ | 57 | 75 | |||||||
MWh sold (in thousands) | 12,447 | 12,452 | — | |||||||||
MWh generated (in thousands) | 11,148 | 10,930 | 2 | |||||||||
Business Metrics | ||||||||||||
Average on-peak market power prices ($/MWh) | $ | 71.25 | $ | 59.62 | 20 | |||||||
Cooling Degree Days, or CDDs(a) | 1,618 | 1,963 | (18 | ) | ||||||||
CDD’s 30 year rolling average | 1,547 | 1,547 | — | |||||||||
Heating Degree Days, or HDDs(a) | 3,672 | 3,236 | 13 | |||||||||
HDD’s 30 year rolling average | 3,623 | 3,604 | 1 | % |
(a) | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
• | Operating revenues —increased by $88 million due to increases in energy revenue and capacity revenue. | |
• | Cost of energy— increased by $56 million due to higher purchased energy, coal transportation costs, natural gas and transmission costs. |
• | Energy revenues— increased by $74 million due to higher merchant energy revenues. A decline in contract sales of 577 thousand MWh allowed for increased sales into the merchant market at higher prices. Merchant |
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energy sales increased 573 thousand MWh. Revenue from contract load was flat as higher fuel cost pass-through adjustments for the region’s cooperative customers were offset by reductions in contract volume to other contract customers. |
• | Capacity revenues— increased by $12 million. Capacity payments from the region’s cooperative customers increased by $10 million due to new peak loads set by the region’s cooperative customers and increased transmission and environmental pass-through costs. Increased RPM capacity payments from the region’s Rockford facilities in the PJM market contributed an additional $8 million. These increases were offset by a reduction in contract volumes to other customers of $6 million. | |
• | Risk Management Activities— gains of $10 million were recognized during 2008 compared to $10 million in gains recognized during the same period in 2007. Unrealized gains in 2008 of $26 million were offset by realized losses of $16 million. The $26 million unrealized gain was the net effect of a $45 million unrealized mark-to-market gain from trading activities in the region offset by the reversal of $19 million loss of previously recognized mark-to-market gains on trading activity. Unrealized gains were primarily driven by decreases in power and gas prices relative to our forward positions. |
• | Purchased energy— increased by $16 million reflecting a 21% increase in the average cost per MWh of purchased energy which reflects higher gas costs associated with the region’s tolling agreements. This increase was offset by an 8% decrease in purchased MWh as increased plant availability and lower contract load requirements reduced the need to purchase power. | |
• | Coal costs— increased by $16 million due to a $2 per ton increase in fuel transportation surcharges combined with a 1% increase in coal generation. These increases were offset by a $3 million decrease in allocated rail car lease fees. | |
• | Natural gas costs — increased $14 million. The region’s Bayou Cove and Big Cajun I peaker plants ran extensively to support transmission system stability after hurricane Gustav in September 2008. | |
• | Transmission costs— increased by $9 million due to additional point-to-point transmission costs driven by an increase in merchant energy sales. |
• | G&A Expense— Franchise tax decreased by $5 million due to retroactive charges recorded in 2007. The Louisiana state franchise tax is assessed on the Company’s total debt and equity that significantly increased following the Acquisition of Texas Genco. This decrease was offset by $6 million in higher corporate allocations in 2008 compared to the same period in 2007. | |
• | Operating and maintenance expense— Major maintenance decreased by $9 million due to more extensive spring outage work performed at the Big Cajun II plant in 2007 compared to the same period in 2008. Normal maintenance rose $2 million as a result of increased forced outages and higher contractor costs. Asset retirements decreased by $4 million reflecting disposals associated with the 2007 outage work at Big Cajun II. |
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Year Ended | ||||||||||||
December 31, | ||||||||||||
2007 | 2006 | Change % | ||||||||||
(In millions except otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 404 | $ | 334 | 21 | % | ||||||
Capacity revenue | 221 | 199 | 11 | |||||||||
Risk management activities | 10 | 13 | (23 | ) | ||||||||
Contract amortization | 23 | 19 | 21 | |||||||||
Other revenues | — | 5 | (100 | ) | ||||||||
Total operating revenues | 658 | 570 | 15 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of energy | 412 | 308 | 34 | |||||||||
Depreciation and amortization | 68 | 68 | — | |||||||||
Other operating expenses | 121 | 89 | 36 | |||||||||
Operating Income | $ | 57 | $ | 105 | (46 | ) | ||||||
MWh sold (in thousands) | 12,452 | 11,845 | 5 | |||||||||
MWh generated (in thousands) | 10,930 | 11,036 | (1 | ) | ||||||||
Business Metrics | ||||||||||||
Average on-peak market power prices ($/MWh) | $ | 59.62 | $ | 56.18 | 6 | |||||||
Cooling Degree Days, or CDDs(a) | 1,963 | 1,797 | 9 | |||||||||
CDD’s 30 year rolling average | 1,547 | 1,547 | — | |||||||||
Heating Degree Days, or HDDs(a) | 3,236 | 3,169 | 2 | % | ||||||||
HDD’s 30 year rolling average | 3,604 | 3,604 | — |
(a) | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
• | Energy revenues— increased by approximately $70 million due to a new contract which contributed $69 million in contract energy revenues, increasing contract sales volume by approximately 1.3 million MWh. A contractual change in the fuel adjustment charge for the region’s cooperative customers increased energy revenues by an additional $11 million. This was offset by a $12 million decrease in merchant energy revenue as a result of satisfying increasing load requirement from the new contract. |
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• | Capacity revenues— increased by approximately $22 million, of which $15 million was due to higher rates as a result of the region setting new summer peaks in 2006 and 2007; the new system peak of 2,123 MW set in August 2007 will continue to impact capacity revenue in the first half of 2008. Higher network transmission costs, which are passed through to the region’s cooperative customers, also increased capacity revenues by $6 million. Improved market conditions in PJM resulted in an increase of $3 million in merchant capacity revenue from the Rockford plants. |
• | Purchased energy— increased by approximately $69 million as planned and maintenance outage hours at the region’s Big Cajun II facility increased by 1,209 hours, primarily due to the planned turbine/generator outage at the Big Cajun II Unit 3 facility in the fourth quarter 2007. These increases were offset by a drop of $2.53/MWh in realized purchased power prices. | |
• | Coal costs— increased by approximately $17 million, of which approximately $11 million was due to a 9% increase in coal prices and $7 million due to higher coal transportation costs. | |
• | Transmission costs— increased by approximately $16 million. Network transmission costs, which are passed-through to the region’s cooperative customers, increased by $6 million due to load growth and increased utilization of the Entergy transmission system. Point-to-point transmission costs to support off-system sales increased by $10 million. |
• | Maintenance expense— increased by approximately $19 million as the scope of work on planned outages were more extensive in 2007. The Big Cajun II Unit 3 facility incurred a major planned outage in the fourth quarter 2007, during which the generator was rewound, turbine controls were replaced with a modern digital control system, and the turbine steam path was replaced with a high-efficiency design. Asset disposals in conjunction with the outage added $4 million. | |
• | Franchise tax— Louisiana state franchise tax increased by approximately $6 million due to an increased assessment based on the Company’s total debt and equity. The Company’s total debt and equity increased significantly following the acquisition of Texas Genco. |
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Year Ended | ||||||||||||
December 31, | ||||||||||||
2008 | 2007 | Change % | ||||||||||
(In millions except otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 39 | $ | 4 | N/A | |||||||
Capacity revenue | 125 | 122 | 2 | % | ||||||||
Risk management activities | — | — | N/A | |||||||||
Other revenues | 7 | 1 | N/A | |||||||||
Total operating revenues | 171 | 127 | 35 | |||||||||
Operating Costs and Expenses | ||||||||||||
Cost of energy | 35 | 5 | N/A | |||||||||
Depreciation and amortization | 8 | 3 | 167 | |||||||||
Other operating expenses | 70 | 80 | (13 | ) | ||||||||
Operating Income | $ | 58 | $ | 39 | 49 | |||||||
MWh sold (in thousands) | 1,532 | 1,246 | 23 | |||||||||
MWh generated (in thousands) | 1,532 | 1,246 | 23 | |||||||||
Business Metrics | ||||||||||||
Average on-peak market power prices ($/MWh) | $ | 82.62 | $ | 66.52 | 24 | |||||||
Cooling Degree Days, or CDDs(a) | 953 | 785 | 21 | |||||||||
CDD’s 30 year rolling average | 704 | 704 | — | |||||||||
Heating Degree Days, or HDDs(a) | 3,190 | 3,048 | 5 | % | ||||||||
HDD’s 30 year rolling average | 3,243 | 3,228 | — |
(a) | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
• | Energy revenues— increased by $35 million due to the 2008 dispatch of the El Segundo plant outside of the tolling agreement in 2008. In 2007, no such dispatch occurred. | |
• | Other operating expense— decreased by $10 million as a result of a $5 million reduction inRepoweringNRG expenses due to the capitalization of cost for the El Segundo Energy Center project in 2008. In addition there was a $3 million reduction in lease expenses in 2008 and the recognition of a $2 million environmental liability for the El Segundo plant in 2007. | |
• | Other revenues— increased by $6 million due to higher allocations for trading of emission allowances in 2008. |
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• | Capacity revenues— increased by $3 million primarily due to the tolling agreement at the Long Beach plant partially offset by the expiration of a two year tolling agreement at the El Segundo facility: |
o | Long Beach— On August 1, 2007, NRG successfully completed the repowering of a 260 MW natural gas-fueled generating plant at its Long Beach generating facility. The plant contributed $15 million in incremental capacity revenues for the year ended December 31, 2008. | |
o | El Segundo— The expiration of the two year tolling agreement at the end of April resulted in a decrease of $11 million in capacity revenues for the year ended December 31, 2008. |
• | Cost of energy —increased by $30 million due to the dispatch of the El Segundo plant outside of the tolling agreement in 2008. In 2007, no such dispatch occurred. | |
• | Depreciation and amortization— increased by $5 million, reflecting depreciation associated with the repowered plant at the Long Beach generating facility. |
Year Ended | ||||||||||||
December 31, | ||||||||||||
2007 | 2006 | Change % | ||||||||||
(In millions except otherwise noted) | ||||||||||||
Operating Revenues | ||||||||||||
Energy revenue | $ | 4 | $ | 75 | (95 | )% | ||||||
Capacity revenue | 122 | 68 | 79 | |||||||||
Risk management activities | — | (3 | ) | 100 | ||||||||
Other revenues | 1 | 6 | (83 | ) | ||||||||
Total operating revenues | 127 | 146 | (13 | ) | ||||||||
Operating Costs and Expenses | ||||||||||||
Cost of energy | 5 | 80 | (94 | ) | ||||||||
Depreciation and amortization | 3 | 3 | — | |||||||||
Other operating expenses | 80 | 55 | 45 | |||||||||
Operating Income | $ | 39 | $ | 8 | 388 | |||||||
MWh sold (in thousands) | 1,246 | 1,901 | (34 | ) | ||||||||
MWh generated (in thousands) | 1,246 | 1,901 | (34 | ) | ||||||||
Business Metrics | ||||||||||||
Average on-peak market power prices ($/MWh) | $ | 66.52 | $ | 61.54 | 8 | |||||||
Cooling Degree Days, or CDDs(a) | 785 | 926 | (15 | ) | ||||||||
CDD’s 30 year rolling average | 704 | 704 | — | |||||||||
Heating Degree Days, or HDDs(a) | 3,048 | 3,001 | 2 | % | ||||||||
HDD’s 30 year rolling average | 3,228 | 3,228 | — |
(a) | National Oceanic and Atmospheric Administration-Climate Prediction Center — A CDD represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
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• | Capacity revenues —increased by approximately $28 million, excluding the first quarter 2007, due to new tolling agreements at the region’s Encina and Long Beach plants: |
o | Encina— In January 2007, NRG signed a new tolling agreement for the region’s Encina plant which contributed $15 million in capacity revenues for the year ended December 31, 2007. | |
o | Long Beach— The repowered plant at the Long Beach generating facility contributed approximately $13 million in capacity revenues for the year ended December 31, 2007. |
• | Cost of energy —decreased by $76 million, excluding the first quarter 2007, due to the new tolling agreement entered into at the Encina plant in 2007, which required the counterparty to supply its own fuel. Under the previous arrangement in 2006, the plant supplied the fuel. |
• | Energy revenues— decreased by approximately $72 million, excluding the first quarter 2007, primarily due to the tolling agreement at the Encina plant that has resulted in the receipt of a fixed monthly capacity payment in return for the right to schedule and dispatch from the plant. The Encina tolling agreement replaced the RMR agreement under which the plant was called upon to generate revenues for such dispatch. | |
• | O&M expense— increased by approximately $6 million, excluding the first quarter 2007, primarily due to increases in labor costs, major maintenance and auxiliary power. | |
• | Development expenses— increased by $4 million, reflectingRepoweringNRG initiatives at the region’s El Segundo and Encina sites. | |
• | Other revenues— decreased ancillary service revenue of $3 million at the Encina plant due to the new tolling agreement that consigns ancillary service revenue to the counterparty in exchange for a fixed monthly capacity payment. |
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As of December 31, | ||||||||
2008 | 2007 | |||||||
(In millions) | ||||||||
Cash and cash equivalents | $ | 1,494 | $ | 1,132 | ||||
Funds deposited by counterparties | 754 | — | ||||||
Restricted cash | 16 | 29 | ||||||
Total cash | 2,264 | 1,161 | ||||||
Synthetic Letter of Credit Facility availability | 860 | 557 | ||||||
Revolver Credit Facility availability | 1,000 | 997 | ||||||
Total liquidity | 4,124 | 2,715 | ||||||
Less: Funds deposited as collateral by hedge counterparties | (760 | ) | — | |||||
Total liquidity, excluding collateral received | $ | 3,364 | $ | 2,715 | ||||
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S&P | Moody’s | Fitch | ||||||||||
NRG Energy, Inc. | B+ | Ba3 | B | |||||||||
7.375% Senior Notes, due 2016, 2017 | B | B1 | B+ | |||||||||
7.25% Senior Notes due 2014 | B | B1 | B+ | |||||||||
Term Loan Facility | BB | Ba1 | BB |
Equivalent Net Sales Secured by First and Second Lien Structure(a) | 2009 | 2010 | 2011 | 2012 | 2013 | |||||||||||||||
In MW(b) | 4,967 | 4,600 | 3,788 | 2,196 | 828 | |||||||||||||||
As a percentage of total forecasted baseload capacity(c) | 71 | % | 67 | % | 56 | % | 33 | % | 12 | % |
(a) | Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region. | |
(b) | 2009 MW value consists of March through December positions only. | |
(c) | Forecasted baseload capacity under the first and second lien structure represents 80% of the total Company’s baseload assets. |
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Subsidiary/Description | 2009 | 2010 | 2011 | 2012 | 2013 | Thereafter | Total | |||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||
Debt: | ||||||||||||||||||||||||||||
7.375% Notes due 2017 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 1,100 | $ | 1,100 | ||||||||||||||
7.25% Notes due 2014 | — | — | — | — | — | 1,200 | 1,200 | |||||||||||||||||||||
7.375% Notes due 2016 | — | — | — | — | — | 2,400 | 2,400 | |||||||||||||||||||||
Term Loan Facility, due 2013 | 228 | 32 | 31 | 32 | 2,319 | — | 2,642 | |||||||||||||||||||||
CSF notes and preferred interests, due 2009 and 2010 | 143 | 190 | — | — | — | — | 333 | |||||||||||||||||||||
NRG Energy Center Minneapolis LLC, due 2013 and 2017 | 11 | 11 | 12 | 13 | 10 | 27 | 84 | |||||||||||||||||||||
Nuclear Innovation North America LLC, due 2011 | — | — | 10 | — | — | — | 10 | |||||||||||||||||||||
NRG Repowering Holdings LLC, due 2011 | — | — | 10 | — | — | — | 10 | |||||||||||||||||||||
NRG Peaker Finance Co. LLC, due June 2019 | 15 | 20 | 21 | 22 | 23 | 165 | 266 | |||||||||||||||||||||
Subtotal Debt, Bonds and Notes | 397 | 253 | 84 | 67 | 2,352 | 4,892 | 8,045 | |||||||||||||||||||||
Capital Lease: | ||||||||||||||||||||||||||||
Saale Energie GmbH, Schkopau | 72 | 12 | 6 | 4 | 4 | 44 | 142 | |||||||||||||||||||||
Total Payments and Capital Leases | $ | 469 | $ | 265 | $ | 90 | $ | 71 | $ | 2,356 | $ | 4,936 | $ | 8,187 | ||||||||||||||
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Maintenance | Environmental | Repowering | Total | |||||||||||||
(In millions) | ||||||||||||||||
Northeast | $ | 32 | $ | 157 | $ | 19 | $ | 208 | ||||||||
Texas | 115 | 26 | 97 | 238 | ||||||||||||
South Central | 9 | 5 | — | 14 | ||||||||||||
West | 5 | — | 30 | 35 | ||||||||||||
Wind | — | — | 398 | 398 | ||||||||||||
NINA | — | — | 101 | 101 | ||||||||||||
Other | 21 | — | — | 21 | ||||||||||||
Total | $ | 182 | $ | 188 | $ | 645 | $ | 1,015 | ||||||||
Estimated capital expenditures for 2009 | $ | 255 | $ | 256 | $ | 256 | $ | 767 | ||||||||
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Texas | Northeast | South Central | Total | |||||||||||||
2009 | $ | — | $ | 256 | $ | — | $ | 256 | ||||||||
2010 | 8 | 213 | 57 | 278 | ||||||||||||
2011 | 17 | 175 | 116 | 308 | ||||||||||||
2012 | 29 | 67 | 114 | 210 | ||||||||||||
2013 | 21 | 3 | 74 | 98 | ||||||||||||
Total | $ | 75 | $ | 714 | $ | 361 | $ | 1,150 | ||||||||
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Year Ended December 31, | ||||||||||||
2008 | 2007 | Change | ||||||||||
(In millions) | ||||||||||||
Net cash provided by operating activities | $ | 1,434 | $ | 1,517 | $ | (83 | ) | |||||
Net cash used by investing activities | (672 | ) | (327 | ) | (345 | ) | ||||||
Net cash used by financing activities | (442 | ) | (814 | ) | 372 |
• | Collateral paid —In 2008, higher cash collateral paid to support the Company’s hedging and trading activities decreased cash from operations by $292 million as compared to the same period in 2007. | |
• | Working capital —In 2008, the cash provided by working capital items increased by $196 million. Changes in option premiums collected from 2007 to 2008 classified in other current liabilities increased as a result of the deferral of option premium revenue to 2009 to match revenues with option expiration dates. Further, changes to account receivable were caused by higher energy revenues in December 2007 as compared to December 2008 and changes to accounts payable were caused by reduced maintenance expenses incurred in December 2007 as compared to December 2008. |
• | Capital expenditures —NRG’s capital expenditures increased by $418 million due toRepoweringNRG projects, primarily related to $398 million for wind turbines and construction activities related to Elbow Creek and other wind projects currently under development. | |
• | Sale of discontinued operations —Proceeds from the sale of ITISA, net of cash divested, were $241 million in 2008. | |
• | Asset sales —The Company received $14 million in proceeds primarily from the sale of rail cars in 2008 compared to proceeds of $57 million for the sale of Red Bluff and Chowchilla II power plants and equipment in the same period in 2007 for a net decrease in cash of $43 million. | |
• | Trading of emission allowances —Net purchases and sales of emission allowances resulted in a decrease in cash of $44 million for 2008 as compared to 2007. | |
• | Equity Contribution —The Company contributed approximately $84 million to its equity investment in Sherbino. |
• | Term Loan Facility debt payment —In 2008, the Company paid down $174 million of its Term Loan Facility, including the payment of excess cash flow, as discussed above underDebt Service Obligations. The Company paid down $332 million of its Term Loan Facility during 2007 for a net cash increase of $158 million for the year ended 2008 compared to the same period in 2007. |
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• | Share repurchase —During 2008, the Company repurchased approximately $185 million shares of NRG common stock, compared to $353 million for 2007 for a net $168 million increase to cash for the year ended 2008 compared to the same period in 2007. | |
• | Sale of minority interest —The Company received $50 million in proceeds from the sale of minority interest in NINA in the first half of 2008. | |
• | Payment of financing element of acquired derivatives —For 2008, the Company paid approximately $43 million for the settlement of gas swaps related to the acquisition of Texas Genco in 2006. | |
• | Issuance of debt —During 2008 the Company received $20 million in proceeds from borrowings made by its subsidiaries. |
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By Remaining Maturity at December 31, | ||||||||||||||||||||||||
2008 | ||||||||||||||||||||||||
Under | Over | 2007 | ||||||||||||||||||||||
Contractual Cash Obligations | 1 Year | 1-3 Years | 3-5 Years | 5 Years | Total(b) | Total | ||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
Long-term debt (including estimated interest) | $ | 858 | $ | 1,316 | $ | 3,267 | $ | 5,701 | $ | 11,142 | $ | 12,301 | ||||||||||||
Capital lease obligations (including estimated interest) | 87 | 37 | 25 | 172 | 321 | 390 | ||||||||||||||||||
Operating leases | 43 | 79 | 62 | 193 | 377 | 420 | ||||||||||||||||||
RepoweringNRG project commitments | 27 | — | — | — | 27 | 352 | ||||||||||||||||||
Fuel purchase and transportation obligations(a) | 1,513 | 477 | 182 | 206 | 2,378 | 3,203 | ||||||||||||||||||
Pension minimum funding requirement(c) | 65 | 95 | 34 | — | 194 | 196 | ||||||||||||||||||
Other postretirement benefits minimum funding requirement(d) | 4 | 11 | 4 | — | 19 | 15 | ||||||||||||||||||
Total | $ | 2,597 | $ | 2,015 | $ | 3,574 | $ | 6,272 | $ | 14,458 | $ | 16,877 | ||||||||||||
(a) | Includes only those coal transportation and lignite commitments for 2009 as no other nominations were made as of December 31, 2008. Natural gas nomination is through February 2010. | |
(b) | Excludes $208 million non-current FIN 48 payable relating to NRG’s uncertain tax benefits as the period of payment cannot be reasonably estimated. | |
(c) | These amounts represent the Company’s estimated minimum pension contributions required under the Pension Protection Act of 2006. These amounts represent estimates that are based on assumptions that are subject to change. The minimum required contribution for years after 2013 is currently not available. | |
(d) | These amounts represent estimates that are based on assumptions that are subject to change. The minimum required contribution for years after 2013 are currently not available. |
By Remaining Maturity at December 31, | ||||||||||||||||||||||||
2008 | ||||||||||||||||||||||||
Under | Over | 2007 | ||||||||||||||||||||||
Guarantees, Indemnifications and Other Contingent Obligations | 1 Year | 1-3 Years | 3-5 Years | 5 Years | Total | Total | ||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
Synthetic letters of credit | $ | 357 | $ | 83 | $ | — | $ | — | $ | 440 | $ | 743 | ||||||||||||
Unfunded standby letters of credit and surety bonds | 5 | — | — | — | 5 | 8 | ||||||||||||||||||
Asset sales guarantee obligations | — | 112 | — | 17 | 129 | 148 | ||||||||||||||||||
Commercial sales arrangements | 192 | 13 | — | 800 | 1,005 | 791 | ||||||||||||||||||
Other guarantees | 24 | 30 | — | 26 | 80 | 32 | ||||||||||||||||||
Total | $ | 578 | $ | 238 | $ | — | $ | 843 | $ | 1,659 | $ | 1,722 | ||||||||||||
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Derivative Activity Gains/(Losses) | (In millions) | |||
Fair value of contracts as of December 31, 2007 | $ | (492 | ) | |
Contracts realized or otherwise settled during the period | 162 | |||
Changes in fair value | 1,326 | |||
Fair value of contracts as of December 31, 2008 | $ | 996 | ||
Fair Value of Contracts as of December 31, 2008 | ||||||||||||||||||||
Maturity | Maturity | |||||||||||||||||||
Less Than | Maturity | Maturity | in Excess | Total Fair | ||||||||||||||||
Sources of Fair Value Gains/(Losses) | 1 Year | 1-3 Years | 4-5 Years | 4-5 Years | Value | |||||||||||||||
(In millions) | ||||||||||||||||||||
Prices actively quoted | $ | (32 | ) | $ | 14 | $ | — | $ | — | $ | (18 | ) | ||||||||
Prices provided by other external sources | 614 | 114 | 283 | (46 | ) | 965 | ||||||||||||||
Prices provided by models and other valuation methods | 37 | 12 | — | — | 49 | |||||||||||||||
Total | $ | 619 | $ | 140 | $ | 283 | $ | (46 | ) | $ | 996 | |||||||||
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Accounting Policy | Judgments/Uncertainties Affecting Application | |||
Derivative Financial Instruments | • | Assumptions used in valuation techniques | ||
• | Assumptions used in forecasting generation | |||
• | Market maturity and economic conditions | |||
• | Contract interpretation | |||
• | Market conditions in the energy industry, especially the effects of price volatility on contractual commitments | |||
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 |
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Accounting Policy | Judgments/Uncertainties Affecting Application | |||
• | 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 | |||
• | Regulatory and political environments and requirements |
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• | Significant decrease in the market price of a long-lived asset; | |
• | Significant adverse change in the manner an asset is being used or its physical condition; | |
• | Adverse business climate; | |
• | Accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset; | |
• | Current-period loss combined with a history of losses or the projection of future losses; and | |
• | Change in the Company’s intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life. |
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• | a discounted cash flow valuation for the region’s major solid fuel baseload plants that utilized the Company’s six-year budget data and a market-derived earnings multiple terminal value, with such terminal value assessed for reasonableness by capitalizing the final year’s cash flow with adjustments for expected inflation; | |
• | a discounted cash flow valuation for the tax benefit associated with the amortization of tax basis of the region’s intangible assets; | |
• | a market approach valuation of the region’s gas plants using market-derived earnings multiples of comparable power generators, with adjustments for the region’s expected capital expenditure requirements; |
• | an overall market approach reasonableness test that reconciled NRG’s current market value based upon the average percent of total company value represented by NRG Texas, as measured by four different earnings measures, each calculated over three different historical time periods. This market approach reasonableness test also considered sensitivity testing under a number of different implied control premium scenarios, including one with no premium. |
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Item 7A — | Quantitative and Qualitative Disclosures about Market Risk |
• | Manage and hedge fixed-price purchase and sales commitments; | |
• | Manage and hedge exposure to variable rate debt obligations; | |
• | Reduce exposure to the volatility of cash market prices; and | |
• | Hedge fuel requirements for the Company’s generating facilities. |
• | Seasonal, daily and hourly changes in demand; | |
• | Extreme peak demands due to weather conditions; | |
• | Available supply resources; | |
• | Transportation availability and reliability within and between regions; and | |
• | Changes in the nature and extent of federal and state regulations. |
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VAR | In millions | |||
As of December 31, 2008 | $ | 43 | ||
Average | 50 | |||
Maximum | 65 | |||
Minimum | 35 | |||
As of December 31, 2007(a) | $ | 64 | ||
Average | 28 | |||
Maximum | 64 | |||
Minimum | 14 |
(a) | Prior to December 4, 2007, NRG’s VAR measurement was based on a rolling24-month forward looking period |
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Maturity | Notional Value | |||
March 31, 2009 | $ | 150 million | ||
March 31, 2010 | $ | 190 million | ||
March 31, 2011 | $ | 1.55 billion |
Notional Value | Maturity | |||||
Floating to fixed interest rate swap for NRG Peaker Financing LLC | $ | 266 million | June 10, 2019 | |||
Fixed to floating interest rate swap for Senior notes, due 2014 | $ | 400 million | December 15, 2013 |
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Net Exposure(a) | ||||
Category | (% of Total) | |||
Coal producers | 16 | % | ||
Financial institutions | 58 | |||
Utilities, energy, merchants and marketers | 21 | |||
ISOs | 5 | |||
Total as of December 31, 2008 | 100 | % | ||
Net Exposure(a) | ||||
Category | (% of Total) | |||
Investment grade | 81 | % | ||
Non-Investment grade | 8 | |||
Non-rated | 11 | |||
Total as of December 31, 2008 | 100 | % | ||
(a) | Credit exposure excludes California tolling, uranium, coal transportation/railcar leases, New England Reliability Must-Run, cooperative load contracts and Texas Westmoreland coal contracts. |
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Item 8 — | Financial Statements and Supplementary Data |
Item 9 — | Changes in and Disagreements with Accountants on Accounting and Financial Disclosures |
Item 9A — | Controls and Procedures |
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• | Reviewing and documenting all mark-to-market logic in our power marketing trading activity system, including any manual adjustments related thereto; | |
• | Formalizing and documenting energy options accounting; | |
• | Formalizing the analysis and review by management of realized and unrealized gain/(loss) derivative accounts; | |
• | Expanding the communication process between accounting, risk management and commercial operations groups to understand derivative accounting results and changes in the commercial operations portfolio; and | |
• | Establishing ongoing training and education in the Company’s accounting group on accounting for derivative option premiums |
1. | Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; | |
2. | Provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and | |
3. | Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated financial statements. |
Item 9B — | Other Information |
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Item 10 — | Directors, Executive Officers and Corporate Governance |
Item 11 — | Executive Compensation |
Item 12 — | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
Item 13 — | Certain Relationships and Related Transactions, and Director Independence |
Item 14 — | Principal Accountant Fees and Services |
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Item 15 — | Exhibits and Financial Statement Schedules |
(b) | Exhibits |
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NRG Energy, Inc.:
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NRG Energy, Inc.:
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For the Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions except per share amounts) | ||||||||||||
Operating Revenues | ||||||||||||
Total operating revenues | $ | 6,885 | $ | 5,989 | $ | 5,585 | ||||||
Operating Costs and Expenses | ||||||||||||
Cost of operations | 3,598 | 3,378 | 3,265 | |||||||||
Depreciation and amortization | 649 | 658 | 590 | |||||||||
General and administrative | 319 | 309 | 276 | |||||||||
Development costs | 46 | 101 | 36 | |||||||||
Total operating costs and expenses | 4,612 | 4,446 | 4,167 | |||||||||
Gain on sale of assets | — | 17 | — | |||||||||
Operating Income | 2,273 | 1,560 | 1,418 | |||||||||
Other Income/(Expense) | ||||||||||||
Equity in earnings of unconsolidated affiliates | 59 | 54 | 60 | |||||||||
Gains on sales of equity method investments | — | 1 | 8 | |||||||||
Other income, net | 17 | 55 | 156 | |||||||||
Refinancing expenses | — | (35 | ) | (187 | ) | |||||||
Interest expense | (620 | ) | (689 | ) | (590 | ) | ||||||
Total other expenses | (544 | ) | (614 | ) | (553 | ) | ||||||
Income From Continuing Operations Before Income Taxes | 1,729 | 946 | 865 | |||||||||
Income tax expense | 713 | 377 | 322 | |||||||||
Income From Continuing Operations | 1,016 | 569 | 543 | |||||||||
Income from discontinued operations, net of income taxes | 172 | 17 | 78 | |||||||||
Net Income | 1,188 | 586 | 621 | |||||||||
Dividends for preferred shares | 55 | 55 | 50 | |||||||||
Income Available for Common Stockholders | $ | 1,133 | $ | 531 | $ | 571 | ||||||
Weighted average number of common shares outstanding — basic | 235 | 240 | 258 | |||||||||
Income from continuing operations per weighted average common share — basic | $ | 4.09 | $ | 2.14 | $ | 1.90 | ||||||
Income from discontinued operations per weighted average common share — basic | 0.73 | 0.07 | 0.31 | |||||||||
Net Income per Weighted Average Common Share — Basic | $ | 4.82 | $ | 2.21 | $ | 2.21 | ||||||
Weighted average number of common shares outstanding — diluted | 275 | 288 | 301 | |||||||||
Income from continuing operations per weighted average common share — diluted | $ | 3.66 | $ | 1.95 | $ | 1.78 | ||||||
Income from discontinued operations per weighted average common share — diluted | 0.63 | 0.06 | 0.26 | |||||||||
Net Income per Weighted Average Common Share — Diluted | $ | 4.29 | $ | 2.01 | $ | 2.04 | ||||||
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As of December 31, | ||||||||
2008 | 2007 | |||||||
(In millions) | ||||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 1,494 | $ | 1,132 | ||||
Funds deposited by counterparties | 754 | — | ||||||
Restricted cash | 16 | 29 | ||||||
Accounts receivable — trade, less allowance for doubtful accounts of $3 and $1 | 464 | 482 | ||||||
Current portion of note receivable— affiliate and capital leases | 68 | 30 | ||||||
Inventory | 455 | 451 | ||||||
Derivative instruments valuation | 4,600 | 1,034 | ||||||
Deferred income taxes | — | 124 | ||||||
Cash collateral paid in support of energy risk management activities | 494 | 85 | ||||||
Prepayments and other current assets | 147 | 144 | ||||||
Current assets — discontinued operations | — | 51 | ||||||
Total current assets | 8,492 | 3,562 | ||||||
Property, Plant and Equipment | ||||||||
In service | 13,084 | 12,678 | ||||||
Under construction | 804 | 337 | ||||||
Total property, plant and equipment | 13,888 | 13,015 | ||||||
Less accumulated depreciation | (2,343 | ) | (1,695 | ) | ||||
Net property, plant and equipment | 11,545 | 11,320 | ||||||
Other Assets | ||||||||
Equity investments in affiliates | 490 | 425 | ||||||
Capital leases and note receivable, less current portion | 435 | 491 | ||||||
Goodwill | 1,718 | 1,786 | ||||||
Intangible assets, net of accumulated amortization of $335 and $372 | 815 | 873 | ||||||
Nuclear decommissioning trust fund | 303 | 384 | ||||||
Derivative instruments valuation | 885 | 150 | ||||||
Other non-current assets | 125 | 190 | ||||||
Non-current assets — discontinued operations | — | 93 | ||||||
Total other assets | 4,771 | 4,392 | ||||||
Total Assets | $ | 24,808 | $ | 19,274 | ||||
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As of December 31, | ||||||||
2008 | 2007 | |||||||
(In millions, except share | ||||||||
data) | ||||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current Liabilities | ||||||||
Current portion of long-term debt and capital leases | $ | 464 | $ | 466 | ||||
Accounts payable — trade | 447 | �� | 381 | |||||
Accounts payable — affiliates | 4 | 3 | ||||||
Derivative instruments valuation | 3,981 | 917 | ||||||
Deferred income taxes | 201 | — | ||||||
Cash collateral received in support of energy risk management activities | 760 | 14 | ||||||
Accrued interest expense | 178 | 185 | ||||||
Other accrued expenses | 215 | 189 | ||||||
Other current liabilities | 331 | 85 | ||||||
Current liabilities — discontinued operations | — | 37 | ||||||
Total current liabilities | 6,581 | 2,277 | ||||||
Other Liabilities | ||||||||
Long-term debt and capital leases | 7,704 | 7,895 | ||||||
Nuclear decommissioning reserve | 284 | 307 | ||||||
Nuclear decommissioning trust liability | 218 | 326 | ||||||
Postretirement and other benefit obligations | 277 | 263 | ||||||
Deferred income taxes | 1,190 | 843 | ||||||
Derivative instruments valuation | 508 | 759 | ||||||
Out-of-market contracts | 291 | 628 | ||||||
Other non-current liabilities | 392 | 149 | ||||||
Non-current liabilities — discontinued operations | — | 76 | ||||||
Total non-current liabilities | 10,864 | 11,246 | ||||||
Total Liabilities | 17,445 | 13,523 | ||||||
Minority Interest | 7 | — | ||||||
3.625% convertible perpetual preferred stock; $0.01 par value; 250,000 shares issued and outstanding (at liquidation value of $250, net of issuance costs) | 247 | 247 | ||||||
Commitments and Contingencies | ||||||||
Stockholders’ Equity | ||||||||
4% convertible perpetual preferred stock; $0.01 par value; 420,000 shares issued and outstanding (at liquidation value of $420, net of issuance costs) | 406 | 406 | ||||||
5.75% convertible perpetual preferred stock; $0.01 par value, 1,841,680 shares issued and outstanding at December 31, 2008, (at liquidation value of $462, net of issuance costs) and 2,000,000 shares issued and outstanding at December 31, 2007 (at liquidation value of $500, net of issuance costs) | 447 | 486 | ||||||
Common Stock; $0.01 par value; 500,000,000 shares authorized; 263,599,200 and 261,285,529 shares issued and 234,356,717 and 236,734,929 shares outstanding at December 31, 2008 and 2007 | 3 | 3 | ||||||
Additionalpaid-in-capital | 4,363 | 4,092 | ||||||
Retained earnings | 2,403 | 1,270 | ||||||
Less treasury stock, at cost — 29,242,483 and 24,550,600 shares at December 31, 2008 and 2007 | (823 | ) | (638 | ) | ||||
Accumulated other comprehensive income/(loss) | 310 | (115 | ) | |||||
Total Stockholders’ Equity | 7,109 | 5,504 | ||||||
Total Liabilities and Stockholders’ Equity | $ | 24,808 | $ | 19,274 | ||||
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Accumulated | ||||||||||||||||||||||||||||||||||||
Additional | Other | Total | ||||||||||||||||||||||||||||||||||
Serial Preferred | Common | Paid-In | Retained | Treasury | Comprehensive | Stockholders’ | ||||||||||||||||||||||||||||||
Stock | Shares | Stock | Shares | Capital | Earnings | Stock | Income/(Loss) | Equity | ||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
Balances at December 31, 2005 | $ | 406 | 0.4 | $ | 3 | 161 | $ | 2,429 | $ | 261 | $ | (663 | ) | $ | (205 | ) | $ | 2,231 | ||||||||||||||||||
Net income | 621 | 621 | ||||||||||||||||||||||||||||||||||
Foreign currency translation adjustments | 60 | 60 | ||||||||||||||||||||||||||||||||||
Unrealized gain on derivatives, net of $135 tax | 405 | 405 | ||||||||||||||||||||||||||||||||||
Minimum pension liability, net of $3 tax | 7 | 7 | ||||||||||||||||||||||||||||||||||
Comprehensive income for 2006 | 1,093 | |||||||||||||||||||||||||||||||||||
Impact upon adoption of SFAS 158, net of $10 tax | 15 | 15 | ||||||||||||||||||||||||||||||||||
Reduction to tax valuation allowance | 17 | 17 | ||||||||||||||||||||||||||||||||||
Impact upon adoption of EITF04-6 | (93 | ) | (93 | ) | ||||||||||||||||||||||||||||||||
Equity-based compensation | 14 | 14 | ||||||||||||||||||||||||||||||||||
Issuance of common stock to the public | 42 | 986 | 986 | |||||||||||||||||||||||||||||||||
Issuance of preferred stock | 486 | 2.0 | 486 | |||||||||||||||||||||||||||||||||
Issuance of common and treasury stock to the shareholders of Texas Genco | 71 | 1,028 | 663 | 1,691 | ||||||||||||||||||||||||||||||||
Preferred stock dividends | (50 | ) | (50 | ) | ||||||||||||||||||||||||||||||||
Purchase of treasury stock | (29 | ) | (732 | ) | (732 | ) | ||||||||||||||||||||||||||||||
Balances at December 31, 2006 | 892 | 2.4 | 3 | 245 | 4,474 | 739 | (732 | ) | 282 | 5,658 | ||||||||||||||||||||||||||
Net income | 586 | 586 | ||||||||||||||||||||||||||||||||||
Foreign currency translation adjustments | 73 | 73 | ||||||||||||||||||||||||||||||||||
Unrealized loss on derivatives, net of $310 tax benefit | (474 | ) | (474 | ) | ||||||||||||||||||||||||||||||||
Available-for-sale securities, net of $1 tax | 2 | 2 | ||||||||||||||||||||||||||||||||||
Defined benefit plan — prior service cost of $4 and net loss of $2, net of $2 tax | 2 | 2 | ||||||||||||||||||||||||||||||||||
Comprehensive income for 2007 | 189 | |||||||||||||||||||||||||||||||||||
Equity-based compensation | 1 | 9 | 9 | |||||||||||||||||||||||||||||||||
Reduction to tax valuation allowance | 56 | 56 | ||||||||||||||||||||||||||||||||||
Preferred stock dividends | (55 | ) | (55 | ) | ||||||||||||||||||||||||||||||||
Purchase of treasury stock | (9 | ) | (353 | ) | (353 | ) | ||||||||||||||||||||||||||||||
Retirement of treasury stock | (447 | ) | 447 | — | ||||||||||||||||||||||||||||||||
Balances at December 31, 2007 | 892 | 2.4 | 3 | 237 | 4,092 | 1,270 | (638 | ) | (115 | ) | 5,504 | |||||||||||||||||||||||||
Net income | 1,188 | 1,188 | ||||||||||||||||||||||||||||||||||
Foreign currency translation adjustments, net of $22 tax | (112 | ) | (112 | ) | ||||||||||||||||||||||||||||||||
Reclassification adjustment for translation loss realized upon sale of ITISA | 15 | 15 | ||||||||||||||||||||||||||||||||||
Unrealized gain on derivatives, net of $369 tax | 580 | 580 | ||||||||||||||||||||||||||||||||||
Available-for-sale securities, net of $2 tax benefit | (4 | ) | (4 | ) | ||||||||||||||||||||||||||||||||
Defined benefit plan — prior service credit of $1 and net loss of $55, net of $35 tax benefit | (54 | ) | (54 | ) | ||||||||||||||||||||||||||||||||
Comprehensive income for 2008 | 1,613 | |||||||||||||||||||||||||||||||||||
Equity-based compensation | 1 | 25 | 25 | |||||||||||||||||||||||||||||||||
Purchase of treasury stock | (5 | ) | (185 | ) | (185 | ) | ||||||||||||||||||||||||||||||
Reduction to tax valuation allowance | 162 | 162 | ||||||||||||||||||||||||||||||||||
Preferred stock dividends | (55 | ) | (55 | ) | ||||||||||||||||||||||||||||||||
NINA contribution, net of $17 tax | 26 | 26 | ||||||||||||||||||||||||||||||||||
5.75% preferred stock conversion to common stock | (39 | ) | (0.1 | ) | 1 | 39 | — | |||||||||||||||||||||||||||||
Other | 19 | 19 | ||||||||||||||||||||||||||||||||||
Balances at December 31, 2008 | $ | 853 | 2.3 | $ | 3 | 234 | $ | 4,363 | $ | 2,403 | $ | (823 | ) | $ | 310 | $ | 7,109 | |||||||||||||||||||
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Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
Cash Flows from Operating Activities | ||||||||||||
Net income | $ | 1,188 | $ | 586 | $ | 621 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities | ||||||||||||
Distributions less than equity in earnings of unconsolidated affiliates | (44 | ) | (33 | ) | (33 | ) | ||||||
Depreciation and amortization | 649 | 661 | 607 | |||||||||
Amortization of nuclear fuel | 39 | 58 | 47 | |||||||||
Amortization and write-off of financing costs and debt discount/premiums | 29 | 66 | 79 | |||||||||
Amortization of intangibles and out-of-market contracts | (270 | ) | (156 | ) | (490 | ) | ||||||
Amortization of unearned equity compensation | 26 | 19 | 14 | |||||||||
Gains on sale of equity method investments | — | (1 | ) | (8 | ) | |||||||
Loss/(gain) on disposals and sales of assets | 25 | (17 | ) | 10 | ||||||||
Impairment charges and asset write downs | 23 | 20 | — | |||||||||
Changes in derivatives | (484 | ) | 77 | (149 | ) | |||||||
Changes in deferred income taxes and liability for unrecognized tax benefits | 762 | 359 | 327 | |||||||||
Gain on legal settlement | — | — | (67 | ) | ||||||||
Gain on sale of discontinued operations | (273 | ) | — | (76 | ) | |||||||
Gain on sale of emission allowances | (51 | ) | (31 | ) | (64 | ) | ||||||
Change in nuclear decommissioning trust liability | 34 | 32 | 12 | |||||||||
Changes in collateral deposits supporting energy risk management activities | (417 | ) | (125 | ) | 454 | |||||||
Settlement of out-of-market power contracts | — | — | (1,073 | ) | ||||||||
Cash provided/(used) by changes in other working capital, net of acquisition and disposition effects | ||||||||||||
Accounts receivable, net | 1 | (102 | ) | 87 | ||||||||
Inventory | (5 | ) | (38 | ) | (50 | ) | ||||||
Prepayments and other current assets | (7 | ) | 22 | 43 | ||||||||
Accounts payable | (31 | ) | 49 | (73 | ) | |||||||
Accrued expenses and other current liabilities | 262 | 106 | 133 | |||||||||
Other assets and liabilities | (22 | ) | (35 | ) | 57 | |||||||
Net Cash Provided by Operating Activities | 1,434 | 1,517 | 408 | |||||||||
Cash Flows from Investing Activities | ||||||||||||
Acquisition of Texas Genco, WCP and Padoma, net of cash acquired | — | — | (4,333 | ) | ||||||||
Capital expenditures | (899 | ) | (481 | ) | (221 | ) | ||||||
Decrease in restricted cash, net | 13 | 12 | 6 | |||||||||
Decrease in notes receivable | 10 | 34 | 27 | |||||||||
Decrease in trust fund balances | — | 19 | — | |||||||||
Purchases of emission allowances | (8 | ) | (161 | ) | (135 | ) | ||||||
Proceeds from sale of emission allowances | 75 | 272 | 146 | |||||||||
Investments in nuclear decommissioning trust fund securities | (616 | ) | (265 | ) | (227 | ) | ||||||
Proceeds from sales of nuclear decommissioning trust fund securities | 582 | 233 | 214 | |||||||||
Proceeds from sale of assets | 14 | 2 | 86 | |||||||||
Equity investment in unconsolidated affiliate | (84 | ) | — | — | ||||||||
Purchases of securities | — | (49 | ) | — | ||||||||
Proceeds from sale of discontinued operations and assets, net of cash divested | 241 | 57 | 260 | |||||||||
Return of capital from equity method investments | — | — | 1 | |||||||||
Net Cash Used by Investing Activities | (672 | ) | (327 | ) | (4,176 | ) | ||||||
Cash Flows from Financing Activities | ||||||||||||
Payment of dividends to preferred stockholders | (55 | ) | (55 | ) | (50 | ) | ||||||
Payment of financing element of acquired derivatives | (43 | ) | — | (296 | ) | |||||||
Payment for treasury stock | (185 | ) | (353 | ) | (732 | ) | ||||||
Proceeds from sale of minority interest in subsidiary | 50 | — | — | |||||||||
Funded letter of credit | — | — | 350 | |||||||||
Proceeds from issuance of common stock, net of issuance costs | 9 | 7 | 986 | |||||||||
Proceeds from issuance of preferred shares, net of issuance costs | — | — | 486 | |||||||||
Proceeds from issuance of long-term debt | 20 | 1,411 | 8,619 | |||||||||
Payment of deferred debt issuance costs | (4 | ) | (5 | ) | (199 | ) | ||||||
Payments for short and long-term debt | (234 | ) | (1,819 | ) | (5,111 | ) | ||||||
Net Cash Provided/(Used) by Financing Activities | (442 | ) | (814 | ) | 4,053 | |||||||
Change in cash from discontinued operations | 43 | (25 | ) | 2 | ||||||||
Effect of exchange rate changes on cash and cash equivalents | (1 | ) | 4 | 4 | ||||||||
Net Increase in Cash and Cash Equivalents | 362 | 355 | 291 | |||||||||
Cash and Cash Equivalents at Beginning of Period | 1,132 | 777 | 486 | |||||||||
Cash and Cash Equivalents at End of Period | $ | 1,494 | $ | 1,132 | $ | 777 | ||||||
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Note 1 — | Nature of Business |
Note 2 — | Summary of Significant Accounting Policies |
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Step one — | Identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value exceeds book value, goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, proceed to step two. | |
Step two — | Compare the implied fair value of the reporting unit’s goodwill to the book value of the reporting unit goodwill. If the book value of goodwill exceeds fair value, an impairment charge is recognized for the sum of such excess. |
• | Current income tax expense or benefit consists solely of regular tax less applicable tax credits, and | |
• | Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts charged or credited to accumulated other comprehensive income. |
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• | Recognized in earnings as an offset to the changes in the fair value of the related hedged assets, liabilities and firm commitments; or | |
• | Deferred and recorded as a component of accumulated OCI until the hedged transactions occur and are recognized in earnings. |
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Total | ||||
(In millions) | ||||
Balance as of December 31, 2007 | $ | 409 | ||
Additions | 1 | |||
Revisions in estimated cashflows | (41 | ) | ||
Accretion — Expense | 7 | |||
Accretion — Other | 17 | |||
Balance as of December 31, 2008 | $ | 393 | ||
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Note 3 — | Discontinued Operations, Business Acquisitions and Dispositions |
Initial Discontinued | ||||||
Operations | ||||||
Project | Segment | Treatment Date | Disposal Date | |||
Audrain | Corporate | Fourth Quarter 2005 | Second Quarter 2006 | |||
Flinders | International | Second Quarter 2006 | Third Quarter 2006 | |||
Resource Recovery | Corporate | Third Quarter 2006 | Fourth Quarter 2006 | |||
ITISA | International | Fourth Quarter 2007 | Second Quarter 2008 |
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As of December 31, | ||||
2007 | ||||
(In millions) | ||||
Cash and cash equivalents | $ | 43 | ||
Restricted cash | 4 | |||
Receivables, net | 4 | |||
Current assets — discontinued operations | $ | 51 | ||
Property, plant and equipment, net | $ | 61 | ||
Other non-current assets | 32 | |||
Non-current assets — discontinued operations | $ | 93 | ||
Current portion of long-term debt | $ | 10 | ||
Accounts payable — trade | 4 | |||
Other current liabilities | 23 | |||
Current liabilities — discontinued operations | $ | 37 | ||
Long-term debt | $ | 51 | ||
Minority interest | 1 | |||
Other non-current liabilities | 24 | |||
Non-current liabilities — discontinued operations | $ | 76 | ||
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
Operating revenues | $ | 20 | $ | 50 | $ | 227 | ||||||
Operating costs and other expenses | 9 | 27 | 224 | |||||||||
Pre-tax income from operations of discontinued components | 11 | 23 | 3 | |||||||||
Income tax expense | 3 | 6 | 1 | |||||||||
Income from operations of discontinued components | 8 | 17 | 2 | |||||||||
Disposal of discontinued components — pre-tax gain | 273 | — | 80 | |||||||||
Income tax expense | 109 | — | 4 | |||||||||
Gain on disposal of discontinued components, net of income taxes | 164 | — | 76 | |||||||||
Income from discontinued operations, net of income taxes | $ | 172 | $ | 17 | $ | 78 | ||||||
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Year Ended December | ||||||||||||||
2008 | 2007 | 2006 | Segment | |||||||||||
(In millions) | ||||||||||||||
ITISA | $ | 273 | $ | — | $ | — | International | |||||||
Resource Recovery | — | — | 5 | Corporate | ||||||||||
Flinders | — | — | 60 | International | ||||||||||
Audrain | — | — | 15 | Corporate | ||||||||||
Total pre-tax gain on disposal of discontinued operations | $ | 273 | $ | — | $ | 80 | ||||||||
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Note 4 — | Fair Value of Financial Instruments |
Year Ended December 31, | ||||||||||||||||
Carrying Amount | Fair Value | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
(In millions) | ||||||||||||||||
Cash and cash equivalents | $ | 1,494 | $ | 1,132 | $ | 1,494 | $ | 1,132 | ||||||||
Funds deposited by counterparties | 754 | — | 754 | — | ||||||||||||
Restricted cash | 16 | 29 | 16 | 29 | ||||||||||||
Cash collateral paid in support of energy risk management activities | 494 | 85 | 494 | 85 | ||||||||||||
Investment in available-for-sale securities (classified within other non-current assets): | ||||||||||||||||
Debt securities | 7 | 32 | 7 | 32 | ||||||||||||
Marketable equity securities | 2 | 7 | 2 | 7 | ||||||||||||
Trust fund investments | 305 | 390 | 305 | 390 | ||||||||||||
Notes receivable | 156 | 126 | 166 | 138 | ||||||||||||
Derivative assets | 5,485 | 1,184 | 5,485 | 1,184 | ||||||||||||
Long-term debt, including current portion | 8,026 | 8,180 | 7,496 | 8,164 | ||||||||||||
Cash collateral received in support of energy risk management activities | 760 | 14 | 760 | 14 | ||||||||||||
Derivative liabilities | 4,489 | 1,676 | 4,489 | 1,676 |
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• | Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability to access as of the measurement date. NRG’s financial assets and liabilities utilizing Level 1 inputs include active exchange-traded securities, energy derivatives, and trust fund investments. | |
• | Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data. NRG’s financial assets and liabilities utilizing Level 2 inputs include fixed income securities, exchange-based derivatives, and over the counter derivatives such as swaps, options and forwards. | |
• | Level 3 — unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset or liability at the measurement date. NRG’s financial assets and liabilities utilizing Level 3 inputs include infrequently-traded, non-exchange-based derivatives and commingled investment funds, and are measured using present value pricing models. |
Fair Value | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | |||||||||||||
(In millions) | ||||||||||||||||
As of December 31, 2008 | ||||||||||||||||
Cash and cash equivalents | $ | 1,494 | $ | — | $ | — | $ | 1,494 | ||||||||
Funds deposited by counterparties | 754 | — | — | 754 | ||||||||||||
Restricted cash | 16 | — | — | 16 | ||||||||||||
Cash collateral paid in support of energy risk management activities | 494 | — | — | 494 | ||||||||||||
Investment in available-for-sale securities (classified within other non-current assets): | ||||||||||||||||
Debt securities | — | — | 7 | 7 | ||||||||||||
Marketable equity securities | 2 | — | — | 2 | ||||||||||||
Trust fund investments | 167 | 107 | 31 | 305 | ||||||||||||
Derivative assets | 2,168 | 3,264 | 53 | 5,485 | ||||||||||||
Total assets | $ | 5,095 | $ | 3,371 | $ | 91 | $ | 8,557 | ||||||||
Cash collateral received in support of energy risk management activities | $ | 760 | $ | — | $ | — | $ | 760 | ||||||||
Derivative liabilities | 2,186 | 2,299 | 4 | 4,489 | ||||||||||||
Total liabilities | $ | 2,946 | $ | 2,299 | $ | 4 | $ | 5,249 | ||||||||
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Fair Value Measurement Using Significant | ||||||||||||||||
Unobservable Inputs | ||||||||||||||||
(Level 3) | ||||||||||||||||
Trust Fund | ||||||||||||||||
Debt Securities | Investments | Derivatives | Total | |||||||||||||
(In millions) | ||||||||||||||||
Year Ended December 31, 2008 | ||||||||||||||||
Beginning balance as of January 1, 2008 | $ | 32 | $ | 37 | $ | 27 | $ | 96 | ||||||||
Total gains and losses (realized/unrealized) Included in earnings | (23 | ) | — | 5 | (18 | ) | ||||||||||
Included in nuclear decommissioning obligations | — | (14 | ) | — | (14 | ) | ||||||||||
Included in other comprehensive income | — | — | 27 | 27 | ||||||||||||
Purchases/(sales), net | (2 | ) | 7 | (10 | ) | (5 | ) | |||||||||
Transfer into Level 3 | — | 1 | — | 1 | ||||||||||||
Ending balance as of December 31, 2008 | $ | 7 | $ | 31 | $ | 49 | $ | 87 | ||||||||
The amount of the total gains or losses for the period included in earnings attributable to the change in unrealized gains and losses relating to assets still held as of December 31, 2008 | $ | (23 | ) | $ | — | $ | (50 | ) | $ | (73 | ) | |||||
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Note 5 — | Accounting for Derivative Instruments and Hedging Activities |
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• | Forward contracts, which commit NRG to sell energy commodities or purchase fuels in the future. | |
• | Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument. | |
• | Swap agreements, which require payments to or from counter-parties based upon the differential between two prices for a predetermined contractual, or notional, quantity. | |
• | Option contracts, which convey the right or obligation to buy or sell a commodity. |
• | Fixing the price for a portion of anticipated future electricity sales through the use of various derivative instruments including gas collars and swaps at a level that provides an acceptable return on the Company’s electric generation operations. | |
• | Fixing the price of a portion of anticipated fuel purchases for the operation of NRG’s power plants. | |
• | Fixing the price of a portion of anticipated energy purchases to supply NRG’s load-serving customers. |
• | Forward and financial contracts for the sale of electricity and related products economically hedging NRG’s generation assets’ forecasted output through 2014. | |
• | Forward and financial contracts for the purchase of fuel commodities relating to the forecasted usage of NRG’s generation assets into 2017. |
• | Power sales and capacity contracts extending to 2025. | |
• | Coal purchase contracts extending through 2012 designated as normal purchases and disclosed as part of NRG’s contractual cash obligations. See also Note 21,Commitments and Contingencies, for further discussion. |
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• | Load-following forward electric sale contracts extending through 2026. | |
• | Power Tolling contracts through 2017. | |
• | Lignite purchase contract through 2018. | |
• | Power transmission contracts through 2011. | |
• | Natural gas transportation contracts and storage agreements through 2018. | |
• | Coal transportation contracts through 2016. |
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Energy-Related | ||||||||||||
Commodities | Interest Rate | Total | ||||||||||
(In millions) | ||||||||||||
Accumulated OCI balance at December 31, 2005 | $ | (204 | ) | $ | 8 | $ | (196 | ) | ||||
Realized from OCI during period — due to unwinding of previously deferred amounts | 6 | (2 | ) | 4 | ||||||||
Changes in fair value of hedge contracts — gains | 391 | 10 | 401 | |||||||||
Accumulated OCI balance at December 31, 2006 | 193 | 16 | 209 | |||||||||
Realized from OCI during period: — due to unwinding of previously deferred amounts | (50 | ) | (2 | ) | (52 | ) | ||||||
Changes in fair value of hedge contracts — losses | (377 | ) | (45 | ) | (422 | ) | ||||||
Accumulated OCI balance at December 31, 2007 | (234 | ) | (31 | ) | (265 | ) | ||||||
Realized from OCI during period — due to unwinding of previously deferred amounts | — | (1 | ) | (1 | ) | |||||||
Changes in fair value of hedge contracts — gains/(losses) | 640 | (59 | ) | 581 | ||||||||
Accumulated OCI balance at December 31, 2008 | $ | 406 | $ | (91 | ) | $ | 315 | |||||
Gains/(losses) expected to unwind from OCI during next 12 months, net of $176 tax | $ | 278 | $ | (1 | ) | $ | 277 | |||||
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Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
Unrealized mark-to-market results | ||||||||||||
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | $ | (38 | ) | $ | (128 | ) | $ | 116 | ||||
Reversal of previously recognized unrealized gains on settled positions related to trading activity | (32 | ) | (32 | ) | (26 | ) | ||||||
Net unrealized gains on open positions related to economic hedges | 524 | 20 | 144 | |||||||||
(Loss)/gain on ineffectiveness associated with open positions treated as cash flow hedges | (24 | ) | 14 | 28 | ||||||||
Net unrealized gains on open positions related to trading activity | 95 | 49 | 33 | |||||||||
Total unrealized mark-to-market results | $ | 525 | $ | (77 | ) | $ | 295 | |||||
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(In millions) | ||||
Settlement payment | $ | (1,347 | ) | |
Reduction in derivative liability | 145 | |||
Reduction in out-of-market contracts | 1,073 | |||
Net decrease in revenues | $ | (129 | ) | |
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Net Exposure(a) | ||||
Category | (% of Total) | |||
Coal producers | 16 | % | ||
Financial institutions | 58 | |||
Utilities, energy, merchants and marketers | 21 | |||
ISOs | 5 | |||
Total as of December 31, 2008 | 100 | % | ||
Net Exposure(a) | ||||
Category | (% of Total) | |||
Investment grade | 81 | % | ||
Non-Investment grade | 8 | |||
Non-rated | 11 | |||
Total as of December 31, 2008 | 100 | % | ||
(a) | Credit exposure excludes California tolling, uranium, coal transportation/railcar leases, New England Reliability Must-Run, cooperative load contracts and Texas Westmoreland coal contracts. |
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Note 6 — | Nuclear Decommissioning Trust Fund |
As of December 31, | ||||||||
2008 | 2007 | |||||||
(In millions) | ||||||||
Cash and cash equivalents | $ | 2 | $ | 4 | ||||
US government and federal agency obligations | 21 | 21 | ||||||
Federal agency mortgage-backed securities | 49 | 59 | ||||||
Commercial mortgage-backed securities | 16 | 22 | ||||||
Corporate debt securities | 37 | 44 | ||||||
Marketable equity securities | 178 | 234 | ||||||
Total | $ | 303 | $ | 384 | ||||
Note 7 — | Inventory |
As of December 31, | ||||||||
2008 | 2007 | |||||||
(In millions) | ||||||||
Fuel oil | $ | 128 | $ | 140 | ||||
Coal/Lignite | 189 | 174 | ||||||
Natural gas | 11 | 16 | ||||||
Spare parts | 127 | 121 | ||||||
Total Inventory | $ | 455 | $ | 451 | ||||
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Note 8 — | Capital Leases and Notes Receivable |
As of December 31, | ||||||||
2008 | 2007 | |||||||
(In millions) | ||||||||
Capital Leases Receivable — non-affiliates | ||||||||
VEAG Vereinigte Energiewerke AG, due August 31, 2021, 11.00%(a) | $ | 338 | $ | 395 | ||||
Other | 9 | — | ||||||
Capital Leases — non-affiliates | 347 | 395 | ||||||
Notes Receivable — affiliates | ||||||||
GenConn Energy LLC, due April 30, 2009, LIBOR + 3.75%(b) — current | 36 | — | ||||||
Kraftwerke Schkopau GBR, indefinite maturity date, 5.89%-7.00%(c) — non-current | 120 | 126 | ||||||
Notes Receivable — affiliates | 156 | 126 | ||||||
Subtotal — Capital leases and notes receivable | 503 | 521 | ||||||
Less current maturities: | ||||||||
Capital leases | 32 | 30 | ||||||
Notes receivable — GenConn | 36 | — | ||||||
Subtotal — current maturities | 68 | 30 | ||||||
Total Capital leases and notes receivable — noncurrent | $ | 435 | $ | 491 | ||||
(a) | Saale Energie GmbH, or SEG, has sold 100% of its share of capacity from the Schkopau power plant to VEAG Vereinigte Energiewerke AG under a25-year contract, which is more than 83% of the useful life of the plant. This direct financing lease receivable amount was calculated based on the present value of the income to be received over the life of the contract. | |
(b) | NRG has entered into a short-term $45 million note receivable facility with GenConn Energy LLC to fund project liquidity needs. | |
(c) | SEG entered into a note receivable with Kraftwerke Schkopau GBR, a partnership between Saale and E.On Kraftwerke GmbH. The note was used to fund SEG’s initial capital contribution to the partnership and to cover project liquidity shortfalls during construction of the Schkopau power plant. The note is subject to repayment upon the disposition of the Schkopau plant. |
Note 9 — | Property, Plant, and Equipment |
As of December 31, | Depreciable | |||||||||||
2008 | 2007 | Lives | ||||||||||
(In millions) | ||||||||||||
Facilities and equipment | $ | 12,193 | $ | 11,829 | 1-40 Years | |||||||
Land and improvements | 593 | 584 | ||||||||||
Nuclear fuel | 225 | 181 | 5 Years | |||||||||
Office furnishings and equipment | 73 | 84 | 2-10 Years | |||||||||
Construction in progress | 804 | 337 | ||||||||||
Total property, plant and equipment | 13,888 | 13,015 | ||||||||||
Accumulated depreciation | (2,343 | ) | (1,695 | ) | ||||||||
Net property, plant and equipment | $ | 11,545 | $ | 11,320 | ||||||||
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Note 10 — | Goodwill and Other Intangibles |
Emission | Contracts | |||||||||||||||||||||||
December 31, 2008 | Allowances | Power | Fuel | Water | Other | Total | ||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
January 1, 2008 | $ | 916 | $ | 92 | $ | 171 | $ | 64 | $ | 2 | $ | 1,245 | ||||||||||||
Additions | 6 | — | — | — | 3 | 9 | ||||||||||||||||||
Transfer to held for sale | (6 | ) | — | — | — | — | (6 | ) | ||||||||||||||||
Fully amortized intangible assets | — | (34 | ) | — | (64 | ) | — | (98 | ) | |||||||||||||||
Adjusted gross amount | 916 | 58 | 171 | — | 5 | 1,150 | ||||||||||||||||||
Less accumulated amortization | (155 | ) | (58 | ) | (122 | ) | — | — | (335 | ) | ||||||||||||||
Net carrying amount | $ | 761 | $ | — | $ | 49 | $ | — | $ | 5 | $ | 815 | ||||||||||||
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Emission | Contracts | |||||||||||||||||||||||
December 31, 2007 | Allowances | Power | Fuel | Water | Other | Total | ||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
January 1, 2007 | $ | 913 | $ | 92 | $ | 171 | $ | 64 | $ | — | $ | 1,240 | ||||||||||||
Additions | 5 | — | — | — | 2 | 7 | ||||||||||||||||||
Sales | (1 | ) | — | — | — | — | (1 | ) | ||||||||||||||||
Transfer to held for sale | (1 | ) | — | — | — | — | (1 | ) | ||||||||||||||||
Adjusted gross amount | 916 | 92 | 171 | 64 | 2 | 1,245 | ||||||||||||||||||
Less accumulated amortization | (114 | ) | (92 | ) | (102 | ) | (64 | ) | — | (372 | ) | |||||||||||||
Net carrying amount | $ | 802 | $ | — | $ | 69 | $ | — | $ | 2 | $ | 873 | ||||||||||||
Amortization | 2008 | 2007 | 2006 | |||||||||
(In millions) | ||||||||||||
Emission allowances | $ | 41 | $ | 40 | $ | 44 | ||||||
Fuel contracts | 20 | 37 | 65 | |||||||||
Water contracts | — | 36 | 28 | |||||||||
Total amortization in cost of operations | $ | 61 | $ | 113 | $ | 137 | ||||||
Power contract amortization recorded as a reduction to operating revenues | $ | — | $ | — | $ | 43 |
Emission | ||||||||||||
Year Ended December 31, | Allowances | Fuel | Total | |||||||||
(In millions) | ||||||||||||
2009 | $ | 40 | $ | 26 | $ | 66 | ||||||
2010 | 52 | 6 | 58 | |||||||||
2011 | 52 | 2 | 54 | |||||||||
2012 | 45 | 2 | 47 | |||||||||
2013 | 20 | 2 | 22 |
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Year Ended December 31, | Coal | Gas Swaps | Power Contracts | Total | ||||||||||||
(In millions) | ||||||||||||||||
2009 | $ | 19 | $ | 56 | $ | 80 | $ | 155 | ||||||||
2010 | 6 | 51 | 28 | 85 | ||||||||||||
2011 | — | — | 21 | 21 | ||||||||||||
2012 | — | — | 22 | 22 | ||||||||||||
2013 | — | — | 19 | 19 |
Note 11 — | Debt and Capital Leases |
As of December 31, | Interest | |||||||||||
2008 | 2007 | Rate | ||||||||||
(In millions except rates) | ||||||||||||
NRG Recourse Debt: | ||||||||||||
Senior notes, due 2017 | $ | 1,100 | $ | 1,100 | 7.375 | |||||||
Senior notes, due 2016 | 2,400 | 2,400 | 7.375 | |||||||||
Senior notes, due 2014(a) | 1,217 | 1,199 | 7.25 | |||||||||
Term Loan Facility, due 2013 | 2,642 | 2,816 | L+1.5 for 2008/ L+1.75 for 2007 | (f) | ||||||||
NRG Non-Recourse Debt: | ||||||||||||
CSF, notes and preferred interests, due 2009 and 2010(b) | 332 | 333 | 5.45-13.23 | |||||||||
NRG Peaker Finance Co. LLC, bonds, due June 2019(c) | 229 | 235 | L+1.07 | (f) | ||||||||
NRG Energy Center Minneapolis LLC, senior secured notes, due 2013 and 2017(d) | 86 | 97 | 7.12-7.31 | |||||||||
Other | 20 | — | L + 0.45 | (f) | ||||||||
Subtotal long term debt | 8,026 | 8,180 | ||||||||||
Capital leases: | ||||||||||||
Saale Energie GmbH, Schkopau capital lease, due 2021 | 142 | 181 | ||||||||||
Subtotal | 8,168 | 8,361 | ||||||||||
Less current maturities(e) | 464 | 466 | ||||||||||
Total | $ | 7,704 | $ | 7,895 | ||||||||
(a) | Includes fair value adjustment as of December 31, 2008 and 2007 of $17 million and $(1) million, respectively, reflecting an adjustment for an interest rate swap. The swap was re-designated from the retired 2nd priority note to this note as part of the financing related to the Texas Genco acquisition. |
(b) | Includes discount of $(1) million as of December 31, 2008. |
(c) | Includes discount of $(37) million and $(43) million as of December 31, 2008 and 2007, respectively. |
(d) | Includes premium of $2 million and $3 million as of December 31, 2008 and 2007, respectively. |
(e) | Includes discount of $6 million and $7 million on the NRG Peaker Finance debt as of December 31, 2008 and 2007, respectively, and a premium of $1 million on NRG Energy Center Minneapolis debt as of December 31, 2008 and 2007. |
(f) | L+ equals LIBOR plus x% |
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• | return capital to shareholders; | |
• | grant liens on assets to lenders; and | |
• | incur additional debt. |
Redemption | ||||
Redemption Period | Percentage | |||
February 1, 2010 to February 1, 2011 | 103.625 | % | ||
February 1, 2011 to February 1, 2012 | 101.813 | % | ||
February 1, 2012 and thereafter | 100.000 | % |
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Redemption | ||||
Redemption Period | Percentage | |||
February 1, 2011 to February 1, 2012 | 103.688 | % | ||
February 1, 2012 to February 1, 2013 | 102.458 | % | ||
February 1, 2013 to February 1, 2014 | 101.229 | % | ||
February 1, 2014 and thereafter | 100.000 | % |
Redemption | ||||
Redemption Period | Percentage | |||
February 1, 2012 to February 1, 2013 | 103.688 | % | ||
February 1, 2013 to February 1, 2014 | 102.458 | % | ||
February 1, 2014 to February 1, 2015 | 101.229 | % | ||
February 1, 2015 and thereafter | 100.000 | % |
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• | incur indebtedness and liens and enter into sale and lease-back transactions; | |
• | make investments, loans and advances; and | |
• | return capital to shareholders. |
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Maturity | Notional Value | |||
March 31, 2009 | $ | 150 million | ||
March 31, 2010 | $ | 190 million | ||
March 31, 2011 | $ | 1.55 billion |
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(In millions) | ||||
2009 | $ | 464 | ||
2010 | 258 | |||
2011 | 85 | |||
2012 | 67 | |||
2013 | 2,352 | |||
Thereafter | 4,942 | |||
Total | $ | 8,168 | ||
(In millions) | ||||
2009 | $ | 87 | ||
2010 | 23 | |||
2011 | 14 | |||
2012 | 13 | |||
2013 | 13 | |||
Thereafter | 172 | |||
Total minimum obligations | 322 | |||
Interest | 180 | |||
Present value of minimum obligations | 142 | |||
Current portion | 72 | |||
Long-term obligations | $ | 70 | ||
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Note 12 — | Benefit Plans and Other Postretirement Benefits |
Year Ended December 31, | ||||||||||||
Pension Benefits | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
Service cost benefits earned | $ | 14 | $ | 15 | $ | 17 | ||||||
Interest cost on benefit obligation | 18 | 17 | 15 | |||||||||
Expected return on plan assets | (14 | ) | (11 | ) | (7 | ) | ||||||
Amortization of unrecognized net gain | (1 | ) | — | — | ||||||||
Net periodic benefit cost | $ | 17 | $ | 21 | $ | 25 | ||||||
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Year Ended December 31, | ||||||||||||
Other Postretirement Benefits | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
Service cost benefits earned | $ | 2 | $ | 2 | $ | 3 | ||||||
Interest cost on benefit obligation | 6 | 5 | 4 | |||||||||
Amortization of unrecognized prior service cost | 1 | — | — | |||||||||
Net periodic benefit cost | $ | 9 | $ | 7 | $ | 7 | ||||||
As of December 31, | ||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
(In millions) | ||||||||||||||||
Benefit obligation at January 1 | $ | 290 | $ | 294 | $ | 83 | $ | 80 | ||||||||
Service cost | 14 | 15 | 2 | 2 | ||||||||||||
Interest cost | 18 | 17 | 6 | 5 | ||||||||||||
Plan amendments | — | (4 | ) | 5 | — | |||||||||||
Actuarial gain | (19 | ) | (13 | ) | (4 | ) | (2 | ) | ||||||||
Benefit payments | (12 | ) | (19 | ) | (1 | ) | (2 | ) | ||||||||
Benefit obligation at December 31 | 291 | 290 | 91 | 83 | ||||||||||||
Fair value of plan assets at January 1 | 168 | 123 | — | — | ||||||||||||
Actual return on plan assets | (60 | ) | 7 | — | — | |||||||||||
Employer contributions | 99 | 58 | 1 | 1 | ||||||||||||
Benefit payments | (12 | ) | (20 | ) | (1 | ) | (1 | ) | ||||||||
Fair value of plan assets at December 31 | 195 | 168 | — | — | ||||||||||||
Funded status at December 31 — excess of obligation over assets | $ | (96 | ) | $ | (122 | ) | $ | (91 | ) | $ | (83 | ) | ||||
As of December 31, | ||||||||||||||||
Other Postretirement | ||||||||||||||||
Pension Benefits | Benefits | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
(In millions) | ||||||||||||||||
Current liabilities | $ | — | $ | — | $ | 2 | $ | — | ||||||||
Non-current liabilities | 96 | 122 | 89 | 83 |
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As of December 31, | ||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
(In millions) | ||||||||||||||||
Unrecognized (gain)/loss | $ | 21 | $ | (36 | ) | $ | (6 | ) | $ | 1 | ||||||
Prior service (credit)/cost | (3 | ) | (3 | ) | 5 | — |
Year Ended December 31, | ||||||||||||||||
Other Postretirement | ||||||||||||||||
Pension Benefits | Benefits | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
(In millions) | ||||||||||||||||
Net loss/(gain) | $ | 55 | $ | (8 | ) | $ | (4 | ) | $ | (2 | ) | |||||
Amortization of net actuarial loss | 1 | — | — | — | ||||||||||||
Prior service (credit)/cost | — | (4 | ) | 5 | — | |||||||||||
Amortization for prior service cost | — | — | (1 | ) | — | |||||||||||
Total recognized in other comprehensive loss/(income) | $ | 56 | $ | (12 | ) | $ | — | $ | (2 | ) | ||||||
Total recognized in net periodic pension cost and other comprehensive income | $ | 73 | $ | 9 | $ | 9 | $ | 5 | ||||||||
As of December 31, | ||||||||
Pension Benefits | ||||||||
2008 | 2007 | |||||||
(In millions) | ||||||||
Projected benefit obligation | $ | 291 | $ | 290 | ||||
Accumulated benefit obligation | 251 | 236 | ||||||
Fair value of plan assets | 195 | 168 |
As of December 31, | ||||||||||||||||
Weighted-Average | Pension Benefits | Other Postretirement Benefits | ||||||||||||||
Assumptions | 2008 | 2007 | 2008 | 2007 | ||||||||||||
Discount rate | 6.88% | 6.56% | 6.88% | 6.56% | ||||||||||||
Rate of compensation increase | 4.00-4.50% | 4.00-4.50% | N/A | N/A | ||||||||||||
Health care trend rate | — | — | 9.5% grading to 5.5% in 2016 | 9.5% grading to 5.5% in 2016 |
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As of December 31, | ||||||||||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||||||||||
Weighted-Average Assumptions | 2008 | 2007 | 2006 | 2008 | 2007 | 2006 | ||||||||||||||||||
Discount rate | 6.56 | % | 5.92 | % | 5.50 | % | 6.56% | 5.92% | 5.50% | |||||||||||||||
Expected return on plan assets | 7.50 | % | 8.00 | % | 8.00 | % | — | — | — | |||||||||||||||
Rate of compensation increase | 4.00-4.50 | % | 4.00-4.50 | % | 4.00-4.50 | % | — | — | — | |||||||||||||||
Health care trend rate | — | — | — | 9.5% grading to 5.5% in 2016 | 10.5% grading to 5.5% in 2012 | 11.5% grading to 5.5% in 2012 |
As of December 31, | ||||||||
2008 | 2007 | |||||||
US Equity | 50-55 | % | 50-55 | % | ||||
International Equity | 15 | % | 15 | % | ||||
US Fixed Income | 30-35 | % | 30-35 | % |
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Other Postretirement Benefit | ||||||||||||
Pension | Medicare Prescription | |||||||||||
Benefit Payments | Benefit Payments | Drug Reimbursements | ||||||||||
(In millions) | ||||||||||||
2009 | $ | 13 | $ | 3 | $ | — | ||||||
2010 | 15 | 3 | — | |||||||||
2011 | 16 | 4 | — | |||||||||
2012 | 18 | 4 | — | |||||||||
2013 | 20 | 4 | — | |||||||||
2014-2018 | 133 | 30 | 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 | 7 | (6 | ) |
As of December 31, | ||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||
(In millions) | ||||||||||||||||
Funded status — STPNOC benefit plans | $ | (48 | ) | $ | (20 | ) | $ | (27 | ) | $ | (22 | ) | ||||
Net periodic benefit costs | 5 | 4 | 3 | 3 | ||||||||||||
Other changes in plan assets and benefit obligations recognized in other comprehensive income | 27 | 4 | 6 | 4 |
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Note 13 — | Capital Structure |
Authorized | Issued | Treasury | Outstanding | |||||||||||||
Balance as of December 31, 2006 | 500,000,000 | 274,248,264 | (29,601,162 | ) | 244,647,102 | |||||||||||
Retirement of shares | — | (14,094,962 | ) | 14,094,962 | — | |||||||||||
Additional Share Repurchases | — | — | (2,037,700 | ) | (2,037,700 | ) | ||||||||||
Capital Allocation Plan — Phase II | — | — | (7,006,700 | ) | (7,006,700 | ) | ||||||||||
Shares issued from LTIP | — | 1,132,227 | — | 1,132,227 | ||||||||||||
Balance as of December 31, 2007 | 500,000,000 | 261,285,529 | (24,550,600 | ) | 236,734,929 | |||||||||||
Capital Allocation Plan — Phase II | — | — | (4,691,883 | ) | (4,691,883 | ) | ||||||||||
Shares issued from LTIP | — | 1,004,176 | — | 1,004,176 | ||||||||||||
5.75% Preferred Stock conversion | — | 1,309,495 | — | 1,309,495 | ||||||||||||
Balance as of December 31, 2008 | 500,000,000 | 263,599,200 | (29,242,483 | ) | 234,356,717 | |||||||||||
Common Stock | ||||
Equity Instrument | Reserve Balance | |||
4% Convertible perpetual preferred | 26,151,972 | |||
3.625% Convertible perpetual preferred | 16,000,000 | |||
5.75% Mandatory convertible preferred | 19,210,505 | |||
Long term incentive plan | 13,561,565 | |||
Total | 74,924,042 | |||
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Applicable Market Value on Conversion Date | Conversion Rate | |||
equal to or greater than $30.23 | 8.2712 | |||
less than $30.23 but greater than $24.38 | 8.2712 to 10.2564 | |||
less than or equal to $24.38 | 10.2564 |
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4% | Preferred Stock |
185
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Note 14 — | Investments Accounted for by the Equity Method |
Economic | ||||||||
Name | Geographic Area | Interest | ||||||
MIBRAG | Germany | 50.0 | % | |||||
Sherbino I Wind Farm LLC | USA | 50.0 | % | |||||
Saguaro Power Company | USA | 50.0 | % | |||||
GenConn Energy LLC | USA | 50.0 | % | |||||
Gladstone Power Station | Australia | 37.5 | % |
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Note 15 — | Gains/(Losses) on Sales of Equity Method Investments |
Year Ended | ||||||||||||
2007 | 2006 | Segment | ||||||||||
(In millions) | ||||||||||||
Powersmith Cogeneration | $ | 1 | $ | — | Corporate | |||||||
Latin American Funds | — | 3 | International | |||||||||
James River Power LLC | — | (6 | ) | Corporate | ||||||||
Cadillac | — | 11 | Corporate | |||||||||
Total gains on sales of equity method investments | $ | 1 | $ | 8 | ||||||||
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Note 16 — | Earnings Per Share |
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
Basic earnings per share | ||||||||||||
Numerator: | ||||||||||||
Income from continuing operations | $ | 1,016 | $ | 569 | $ | 543 | ||||||
Preferred stock dividends | (55 | ) | (55 | ) | (52 | ) | ||||||
Net income available to common stockholders from continuing operations | 961 | 514 | 491 | |||||||||
Discontinued operations, net of tax | 172 | 17 | 78 | |||||||||
Net income available to common stockholders | $ | 1,133 | $ | 531 | $ | 569 | ||||||
Denominator: | ||||||||||||
Weighted average number of common shares outstanding | 235.0 | 240.2 | 258.0 | |||||||||
Basic earnings per share: | ||||||||||||
Income from continuing operations | $ | 4.09 | $ | 2.14 | $ | 1.90 | ||||||
Discontinued operations, net of tax | 0.73 | 0.07 | 0.31 | |||||||||
Net income | $ | 4.82 | $ | 2.21 | $ | 2.21 | ||||||
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Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
Diluted earnings per share | ||||||||||||
Numerator: | ||||||||||||
Net income available to common stockholders from continuing operations | $ | 961 | $ | 514 | $ | 491 | ||||||
Add preferred stock dividends for dilutive preferred stock | 46 | 46 | 43 | |||||||||
Adjusted income from continuing operations available to common stockholders | 1,007 | 560 | 534 | |||||||||
Discontinued operations, net of tax | 172 | 17 | 78 | |||||||||
Net income available to common stockholders | $ | 1,179 | $ | 577 | $ | 612 | ||||||
Denominator: | ||||||||||||
Weighted average number of common shares outstanding | 235.0 | 240.2 | 258.0 | |||||||||
Incremental shares attributable to the issuance of equity compensation (treasury stock method) | 2.3 | 3.8 | 2.8 | |||||||||
Incremental shares attributable to embedded derivatives of certain financial instruments (if-converted method) | — | 6.0 | — | |||||||||
Incremental shares attributable to the assumed conversion features of outstanding preferred stock (if-converted method) | 37.5 | 37.5 | 39.8 | |||||||||
Total dilutive shares | 274.8 | 287.5 | 300.6 | |||||||||
Diluted earnings per share: | ||||||||||||
Income from continuing operations available to common stockholders | $ | 3.66 | $ | 1.95 | $ | 1.78 | ||||||
Discontinued operations, net of tax | 0.63 | 0.06 | 0.26 | |||||||||
Net income | $ | 4.29 | $ | 2.01 | $ | 2.04 | ||||||
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions of shares) | ||||||||||||
Equity compensation — NQSO’s and PU’s | 1.9 | 0.1 | 0.7 | |||||||||
Embedded derivative of 3.625% redeemable perpetual preferred stock | 16.0 | 12.2 | 16.0 | |||||||||
Embedded derivatives of CSF preferred interests and notes | 7.6 | 16.1 | 18.3 | |||||||||
Total | 25.5 | 28.4 | 35.0 | |||||||||
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Note 17 — | Segment Reporting |
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
Customer A — Northeast region | — | % | — | % | 10 | % | ||||||
Customer B — Texas region | 11 | — | — | |||||||||
Customer C — Texas region | 11 | 27 | — | |||||||||
Total | 22 | % | 27 | % | 10 | % | ||||||
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Year Ended December 31, 2008 | ||||||||||||||||||||||||||||||||||||
Wholesale Power Generation | ||||||||||||||||||||||||||||||||||||
South | ||||||||||||||||||||||||||||||||||||
Texas | Northeast | Central | West | International | Thermal | Corporate | Elimination | Total | ||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
Operating revenues | $ | 4,026 | $ | 1,630 | $ | 746 | $ | 171 | $ | 158 | $ | 154 | $ | 3 | $ | (3 | ) | $ | 6,885 | |||||||||||||||||
Operating expenses | 1,890 | 1,087 | 579 | 105 | 133 | 122 | 52 | (5 | ) | 3,963 | ||||||||||||||||||||||||||
Depreciation and amortization | 451 | 109 | 67 | 8 | — | 10 | 4 | — | 649 | |||||||||||||||||||||||||||
Operating income/(loss) | 1,685 | 434 | 100 | 58 | 25 | 22 | (53 | ) | 2 | 2,273 | ||||||||||||||||||||||||||
Equity in earnings/(loss) of unconsolidated affiliates | 9 | — | — | (2 | ) | 52 | — | — | — | 59 | ||||||||||||||||||||||||||
Other income, net | 9 | 12 | 1 | 1 | 5 | — | 20 | (31 | ) | 17 | ||||||||||||||||||||||||||
Interest expense | (100 | ) | (56 | ) | (51 | ) | (6 | ) | — | (6 | ) | (420 | ) | 19 | (620 | ) | ||||||||||||||||||||
Income/(loss) from continuing operations before income taxes | 1,603 | 390 | 50 | 51 | 82 | 16 | (453 | ) | (10 | ) | 1,729 | |||||||||||||||||||||||||
Income tax expense | 692 | — | — | — | 19 | — | 2 | — | 713 | |||||||||||||||||||||||||||
Income/(loss) from continuing operations | 911 | 390 | 50 | 51 | 63 | 16 | (455 | ) | (10 | ) | 1,016 | |||||||||||||||||||||||||
Income from discontinued operations, net of income taxes | — | — | — | — | 172 | — | — | — | 172 | |||||||||||||||||||||||||||
Net income/(loss) | $ | 911 | $ | 390 | $ | 50 | $ | 51 | $ | 235 | $ | 16 | $ | (455 | ) | $ | (10 | ) | $ | 1,188 | ||||||||||||||||
Balance sheet | ||||||||||||||||||||||||||||||||||||
Equity investments in affiliates | $ | 92 | $ | 1 | $ | — | $ | 25 | $ | 372 | $ | — | $ | — | $ | — | $ | 490 | ||||||||||||||||||
Capital expenditures | 238 | 208 | 14 | 35 | — | 11 | 509 | — | 1,015 | |||||||||||||||||||||||||||
Goodwill | 1,713 | — | — | — | — | — | 5 | — | 1,718 | |||||||||||||||||||||||||||
Total assets | $ | 12,899 | $ | 1,667 | $ | 933 | $ | 264 | $ | 973 | $ | 208 | $ | 20,208 | $ | (12,344 | ) | $ | 24,808 |
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Year Ended December 31, 2007 | ||||||||||||||||||||||||||||||||||||
Wholesale Power Generation | ||||||||||||||||||||||||||||||||||||
South | ||||||||||||||||||||||||||||||||||||
Texas | Northeast | Central | West | International | Thermal | Corporate | Elimination | Total | ||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
Operating revenues | $ | 3,287 | $ | 1,605 | $ | 658 | $ | 127 | $ | 140 | $ | 159 | $ | 30 | $ | (17 | ) | $ | 5,989 | |||||||||||||||||
Operating expenses | 1,849 | 1,045 | 533 | 85 | 112 | 125 | 47 | (8 | ) | 3,788 | ||||||||||||||||||||||||||
Depreciation and amortization | 469 | 102 | 68 | 3 | — | 11 | 5 | — | 658 | |||||||||||||||||||||||||||
Gain/(loss) on sale of assets | — | — | — | — | — | 18 | (1 | ) | — | 17 | ||||||||||||||||||||||||||
Operating income/(loss) | 969 | 458 | 57 | 39 | 28 | 41 | (23 | ) | (9 | ) | 1,560 | |||||||||||||||||||||||||
Equity in earnings/(loss) of unconsolidated affiliates | — | — | — | (3 | ) | 57 | — | — | — | 54 | ||||||||||||||||||||||||||
Gains on sale of equity method investment | — | — | — | — | — | — | 1 | — | 1 | |||||||||||||||||||||||||||
Other income, net | 7 | — | — | — | 8 | 1 | 58 | (19 | ) | 55 | ||||||||||||||||||||||||||
Refinancing expenses | — | — | — | — | — | — | (35 | ) | — | (35 | ) | |||||||||||||||||||||||||
Interest expense | (164 | ) | (57 | ) | (53 | ) | — | (5 | ) | (6 | ) | (423 | ) | 19 | (689 | ) | ||||||||||||||||||||
Income/(loss) from continuing operations before income taxes | 812 | 401 | 4 | 36 | 88 | 36 | (422 | ) | (9 | ) | 946 | |||||||||||||||||||||||||
Income tax expense/(benefit) | 327 | — | — | — | (12 | ) | — | 62 | — | 377 | ||||||||||||||||||||||||||
Income/(loss) from continuing operations | 485 | 401 | 4 | 36 | 100 | 36 | (484 | ) | (9 | ) | 569 | |||||||||||||||||||||||||
Income from discontinued operations, net of income taxes | — | — | — | — | 17 | — | — | — | 17 | |||||||||||||||||||||||||||
Net income/(loss) | $ | 485 | $ | 401 | $ | 4 | $ | 36 | $ | 117 | $ | 36 | $ | (484 | ) | $ | (9 | ) | $ | 586 | ||||||||||||||||
Balance sheet | ||||||||||||||||||||||||||||||||||||
Equity investments in affiliates | $ | — | $ | 1 | $ | — | $ | 27 | $ | 397 | $ | — | $ | — | $ | — | $ | 425 | ||||||||||||||||||
Capital expenditures | 190 | 106 | 30 | 80 | — | 6 | 69 | — | 481 | |||||||||||||||||||||||||||
Goodwill | 1,781 | — | — | — | — | — | 5 | — | 1,786 | |||||||||||||||||||||||||||
Total assets | $ | 12,165 | $ | 1,572 | $ | 995 | $ | 246 | $ | 1,169 | $ | 211 | $ | 12,847 | $ | (9,931 | ) | $ | 19,274 |
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Year Ended December 31, 2006 | ||||||||||||||||||||||||||||||||||||
Wholesale Power Generation | ||||||||||||||||||||||||||||||||||||
South | ||||||||||||||||||||||||||||||||||||
Texas | Northeast | Central | West | International | Thermal | Corporate | Elimination | Total | ||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||||||
Operating revenues | $ | 3,088 | $ | 1,543 | $ | 570 | $ | 146 | $ | 135 | $ | 152 | $ | 12 | $ | (61 | ) | $ | 5,585 | |||||||||||||||||
Operating expenses | 1,794 | 993 | 397 | 135 | 110 | 121 | 30 | (3 | ) | 3,577 | ||||||||||||||||||||||||||
Depreciation and amortization | 413 | 89 | 68 | 3 | — | 12 | 5 | — | 590 | |||||||||||||||||||||||||||
Operating income/(loss) | 881 | 461 | 105 | 8 | 25 | 19 | (23 | ) | (58 | ) | 1,418 | |||||||||||||||||||||||||
Equity in earnings of unconsolidated affiliates | — | — | — | 1 | 57 | — | 2 | — | 60 | |||||||||||||||||||||||||||
Gains on sales of equity method investments | — | — | — | — | 3 | — | 5 | — | 8 | |||||||||||||||||||||||||||
Other income, net | 9 | 6 | — | 1 | 7 | 1 | 152 | (20 | ) | 156 | ||||||||||||||||||||||||||
Refinancing expenses | — | — | — | — | — | — | (187 | ) | — | (187 | ) | |||||||||||||||||||||||||
Interest expense | (138 | ) | (63 | ) | (57 | ) | — | (1 | ) | (7 | ) | (344 | ) | 20 | (590 | ) | ||||||||||||||||||||
Income/(loss) from continuing operations before income taxes | 752 | 404 | 48 | 10 | 91 | 13 | (395 | ) | (58 | ) | 865 | |||||||||||||||||||||||||
Income tax expense/(benefit) | 23 | — | — | (2 | ) | 23 | — | 278 | — | 322 | ||||||||||||||||||||||||||
Income/(loss) from continuing operations | 729 | 404 | 48 | 12 | 68 | 13 | (673 | ) | (58 | ) | 543 | |||||||||||||||||||||||||
Income from discontinued operations, net of income taxes | — | — | — | — | 61 | — | 17 | — | 78 | |||||||||||||||||||||||||||
Net income/(loss) | $ | 729 | $ | 404 | $ | 48 | $ | 12 | $ | 129 | $ | 13 | $ | (656 | ) | $ | (58 | ) | $ | 621 | ||||||||||||||||
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Note 18 — | Income Taxes |
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
Current | ||||||||||||
US Federal | $ | 89 | $ | (6 | ) | $ | (26 | ) | ||||
State | 31 | (1 | ) | (1 | ) | |||||||
Foreign | 17 | 20 | 19 | |||||||||
137 | 13 | (8 | ) | |||||||||
Deferred | ||||||||||||
US Federal | 539 | 347 | 288 | |||||||||
State | 35 | 47 | 38 | |||||||||
Foreign | 2 | (30 | ) | 4 | ||||||||
576 | 364 | 330 | ||||||||||
Total income tax | $ | 713 | $ | 377 | $ | 322 | ||||||
Effective tax rate | 41.2 | % | 39.9 | % | 37.2 | % |
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
US | $ | 1,644 | $ | 860 | $ | 767 | ||||||
Foreign | 85 | 86 | 98 | |||||||||
Total | $ | 1,729 | $ | 946 | $ | 865 | ||||||
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Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions, except percentages) | ||||||||||||
Income from continuing operations before income taxes | $ | 1,729 | $ | 946 | $ | 865 | ||||||
Tax at 35% | 605 | 331 | 303 | |||||||||
State taxes, net of federal benefit | 73 | 46 | 34 | |||||||||
Foreign operations | (10 | ) | (13 | ) | (21 | ) | ||||||
Subpart F taxable income | 2 | — | 11 | |||||||||
Valuation allowance, including change in state effective rate | (12 | ) | 6 | (10 | ) | |||||||
Change in state effective tax rate | (11 | ) | — | 21 | ||||||||
Claimant reserve settlements | — | — | (28 | ) | ||||||||
Change in local German effective tax rates | — | (29 | ) | — | ||||||||
Foreign dividends | 32 | 26 | 1 | |||||||||
Non-deductible interest | 26 | 10 | 3 | |||||||||
Permanent differences, reserves, other | 8 | — | 8 | |||||||||
Income tax expense | $ | 713 | $ | 377 | $ | 322 | ||||||
Effective income tax rate | 41.2 | % | 39.9 | % | 37.2 | % |
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As of December 31, | ||||||||
2008 | 2007 | |||||||
(In millions) | ||||||||
Deferred tax liabilities: | ||||||||
Discount/premium on notes | $ | 13 | $ | 23 | ||||
Emissions allowances | 112 | 109 | ||||||
Difference between book and tax basis of property | 1,477 | 1,568 | ||||||
Derivatives, net | 440 | — | ||||||
Goodwill | 73 | 45 | ||||||
Anticipated repatriation of foreign earnings | 26 | — | ||||||
Cumulative translation adjustments | 22 | — | ||||||
Investment in projects | — | 6 | ||||||
Total deferred tax liabilities | 2,163 | 1,751 | ||||||
Deferred tax assets: | ||||||||
Deferred compensation, pension, accrued vacation and other reserves | 126 | 129 | ||||||
Derivatives, net | — | 125 | ||||||
Differences between book and tax basis of contracts | 377 | 577 | ||||||
Non-depreciable property | 19 | 19 | ||||||
Intangibles amortization (excluding goodwill) | 164 | 152 | ||||||
Equity compensation | 22 | 15 | ||||||
Claimants reserve | 10 | 7 | ||||||
US capital loss carryforwards | 274 | 439 | ||||||
Foreign net operating loss carryforwards | 66 | 80 | ||||||
State net operating loss carryforwards | 28 | — | ||||||
Foreign capital loss carryforwards | 1 | 1 | ||||||
Investments in projects | 10 | — | ||||||
Deferred financing costs | 10 | 12 | ||||||
Alternative minimum tax | 20 | 3 | ||||||
Other | 4 | 12 | ||||||
Total deferred tax assets | 1,131 | 1,571 | ||||||
Valuation allowance | (359 | ) | (539 | ) | ||||
Net deferred tax assets | 772 | 1,032 | ||||||
Net deferred tax liability | $ | 1,391 | $ | 719 | ||||
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As of December 31, | ||||||||
2008 | 2007 | |||||||
(In millions) | ||||||||
Current deferred tax asset | $ | — | $ | 124 | ||||
Current deferred tax liability | 201 | — | ||||||
Non-current deferred tax liability | 1,190 | 843 | ||||||
Net deferred tax liability | $ | 1,391 | $ | 719 | ||||
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As of | As of | |||||||
December 31, | December 31, | |||||||
2008 | 2007 | |||||||
(In millions) | (In millions) | |||||||
Balance as of January 1 | $ | 683 | $ | 712 | ||||
Increase due to current year positions | 18 | 76 | ||||||
Decrease due to current year positions | (183 | ) | (105 | ) | ||||
Increase due to prior year positions | 9 | — | ||||||
Decrease due to prior year positions | — | — | ||||||
Decrease due to settlements and payments | — | — | ||||||
Decrease due to statute expirations | — | — | ||||||
Unrecognized tax benefits as of December 31 | $ | 527 | $ | 683 | ||||
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Note 19 — | Stock-Based Compensation |
Weighted | ||||||||||||||||
Average | ||||||||||||||||
Weighted | Remaining | Aggregate | ||||||||||||||
Average | Contractual Term | Intrinsic Value | ||||||||||||||
Shares | Exercise Price | (in years) | (In millions) | |||||||||||||
(In whole) | ||||||||||||||||
Outstanding at December 31, 2007 | 3,579,775 | $ | 19.98 | |||||||||||||
Granted | 1,206,800 | 39.94 | ||||||||||||||
Forfeited | (250,401 | ) | 30.09 | |||||||||||||
Exercised | (527,986 | ) | 16.41 | |||||||||||||
Outstanding at December 31, 2008 | 4,008,188 | 25.84 | 4 | $ | 14 | |||||||||||
Exercisable at December 31, 2008 | 2,009,205 | 17.55 | 4 | 14 | ||||||||||||
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2008 | 2007 | 2006 | ||||
Expected volatility | 26.75%-44.00% | 25.88%-27.28% | 27.95%-29.64% | |||
Expected term (in years) | 4 | 4 | 4-6 | |||
Risk free rate | 1.33%-3.09% | 4.58%-4.68% | 4.30%-5.05% |
Weighted Average | ||||||||
Grant-Date Fair | ||||||||
Units | Value per Unit | |||||||
(In whole) | ||||||||
Non-vested at December 31, 2007 | 1,588,316 | $ | 26.99 | |||||
Granted | 166,400 | 39.84 | ||||||
Forfeited | (81,900 | ) | 32.23 | |||||
Vested | (610,820 | ) | 19.38 | |||||
Non-vested at December 31, 2008 | 1,061,996 | 32.97 | ||||||
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Weighted Average | ||||||||
Grant-Date Fair | ||||||||
Units | Value per Unit | |||||||
(In whole) | ||||||||
Outstanding at December 31, 2007 | 268,994 | $ | 18.06 | |||||
Granted | 29,614 | 35.12 | ||||||
Conversions | (37,840 | ) | 28.41 | |||||
Outstanding at December 31, 2008 | 260,768 | 18.50 | ||||||
Weighted Average | ||||||||
Outstanding | Grant-Date Fair | |||||||
Units | Value per Unit | |||||||
(In whole except weighted average data) | ||||||||
Non-vested at December 31, 2007 | 536,764 | $ | 20.18 | |||||
Granted | 233,700 | 26.99 | ||||||
Vested | (50,000 | ) | 15.74 | |||||
Forfeited | (60,900 | ) | 21.65 | |||||
Non-vested at December 31, 2008 | 659,564 | 22.81 | ||||||
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2008 | 2007 | 2006 | ||||
Expected volatility | 27.81%-48.06% | 25.91%-27.28% | 27.95%-29.64% | |||
Expected term (in years) | 3 | 3 | 3-5 | |||
Risk free rate | 1.13%-2.89% | 4.54%-4.69% | 4.30%-5.04% |
Non-vested Compensation Cost | ||||||||||||||||||||
Weighted Average | ||||||||||||||||||||
Recognition Period | ||||||||||||||||||||
Unrecognized | Remaining | |||||||||||||||||||
Compensation Expense | Total Cost | (In years) | ||||||||||||||||||
Year Ended December 31 | As of December 31 | |||||||||||||||||||
Award | 2008 | 2007 | 2006 | 2008 | 2008 | |||||||||||||||
(In millions, except weighted average data) | ||||||||||||||||||||
NQSO’s | $ | 8 | $ | 5 | $ | 5 | $ | 11 | 1.2 | |||||||||||
RSU’s | 12 | 10 | 10 | 18 | 1.2 | |||||||||||||||
DSU’s | 1 | 1 | 1 | — | — | |||||||||||||||
PU’s | 5 | 3 | 2 | 6 | 1.1 | |||||||||||||||
Total | $ | 26 | $ | 19 | $ | 18 | $ | 35 | ||||||||||||
Tax benefit recognized | $ | 10 | $ | 8 | $ | 7 | ||||||||||||||
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Note 20 — | Related Party Transactions |
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
Revenues from Related Parties Included in Operating Revenues | ||||||||||||
MIBRAG | $ | 4 | $ | 4 | $ | 4 | ||||||
Gladstone | 2 | 1 | 2 | |||||||||
GenConn | 1 | — | — | |||||||||
Sherbino | 1 | — | — | |||||||||
WCP(a) | — | — | 1 | |||||||||
Total | $ | 8 | $ | 5 | $ | 7 | ||||||
Expenses from Related Parties Included in Cost of Operations | ||||||||||||
MIBRAG | ||||||||||||
Cost of purchased coal | $ | 57 | $ | 43 | $ | 43 | ||||||
(a) | For the period January 1, 2006 to March 31, 2006. |
Note 21 — | Commitments and Contingencies |
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Period | (In millions) | |||
2009 | $ | 43 | ||
2010 | 41 | |||
2011 | 38 | |||
2012 | 33 | |||
2013 | 29 | |||
Thereafter | 193 | |||
Total | $ | 377 | ||
Period | (In millions) | |||
2009 | $ | 1,513 | ||
2010 | 294 | |||
2011 | 183 | |||
2012 | 151 | |||
2013 | 31 | |||
Thereafter | 206 | |||
Total(a) | $ | 2,378 | ||
(a) | Includes those coal transportation and lignite commitments for 2009 as no other nominations were made as of December 31, 2008. Natural gas nomination is through February 2010. |
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Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
Interest paid, net of amount capitalized(a) | $ | 563 | $ | 598 | $ | 450 | ||||||
Income taxes paid(b) | 46 | 22 | 18 | |||||||||
Non-cash investing and financing activities: | ||||||||||||
(Reduction)/addition to fixed assets due to asset retirement obligations | (39 | ) | 7 | 15 | ||||||||
Additions to fixed assets for accrued capital expenditures | 116 | — | — | |||||||||
Decrease to 5.75% preferred stock from conversion to common stock | (39 | ) | — | — |
(a) | 2008 interest paid includes $45 million payment to settle the CSF I CAGR. |
(b) | 2008 and 2007 income taxes paid is net of $2 and $6 million, respectively, of income tax refunds received. |
By Remaining Maturity at December 31, | ||||||||||||||||||||||||
2008 | ||||||||||||||||||||||||
Under | Over | 2007 | ||||||||||||||||||||||
Guarantees | 1 Year | 1-3 Years | 3-5 Years | 5 Years | Total | Total | ||||||||||||||||||
(In millions) | ||||||||||||||||||||||||
Synthetic letters of credit | $ | 357 | $ | 83 | $ | — | $ | — | $ | 440 | $ | 743 | ||||||||||||
Unfunded letters of credit and surety bonds | 5 | — | — | — | 5 | 8 | ||||||||||||||||||
Asset sales guarantee obligations | — | 112 | — | 17 | 129 | 148 | ||||||||||||||||||
Commercial sales arrangements | 192 | 13 | — | 800 | 1,005 | 791 | ||||||||||||||||||
Other guarantees | 24 | 30 | — | 26 | 80 | 32 | ||||||||||||||||||
Total guarantees | $ | 578 | $ | 238 | $ | — | $ | 843 | $ | 1,659 | $ | 1,722 | ||||||||||||
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Ownership | Property, Plant & | Accumulated | Construction in | |||||||||||||
As of December 31, 2008 | Interest | Equipment | Depreciation | Progress | ||||||||||||
(In millions unless otherwise stated) | ||||||||||||||||
South Texas Project Units 1 and 2, Bay City, TX | 44.00 | % | $ | 2,918 | $ | (503 | ) | $ | 34 | |||||||
Big Cajun II Unit 3, New Roads, LA | 58.00 | 174 | (48 | ) | 10 | |||||||||||
Cedar Bayou Unit 4, Baytown, TX | 50.00 | — | — | 185 | ||||||||||||
Keystone, Shelocta, PA | 3.70 | 61 | (15 | ) | 20 | |||||||||||
Conemaugh, New Florence, PA | 3.72 | 74 | (19 | ) | 1 |
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Quarter Ended | ||||||||||||||||
2008 | ||||||||||||||||
September 30 | ||||||||||||||||
December 31 | (As revised) | June 30 | March 31 | |||||||||||||
(In millions, except per share data) | ||||||||||||||||
Operating revenues | $ | 1,655 | $ | 2,612 | $ | 1,316 | $ | 1,302 | ||||||||
Operating income | 595 | 1,371 | 57 | 250 | ||||||||||||
Income/(loss) from continuing operations, net of income taxes | 273 | 734 | (39 | ) | 48 | |||||||||||
Income from discontinued operations, net of income taxes | — | — | 168 | 4 | ||||||||||||
Net income | $ | 273 | $ | 734 | $ | 129 | $ | 52 | ||||||||
Weighted average number of common shares outstanding — basic | 233 | 235 | 236 | 236 | ||||||||||||
Income/(loss) from continuing operations per weighted average common share — basic | $ | 1.11 | $ | 3.07 | $ | (0.22 | ) | $ | 0.14 | |||||||
Income from discontinued operations per weighted average common share — basic | — | — | 0.71 | 0.02 | ||||||||||||
Net income per weighted average common share — basic | $ | 1.11 | $ | 3.07 | $ | 0.49 | $ | 0.16 | ||||||||
Weighted average number of common shares outstanding — diluted | 276 | 277 | 236 | 245 | ||||||||||||
Income/(loss) from continuing operations per weighted average common share — diluted | $ | 0.98 | $ | 2.65 | $ | (0.22 | ) | $ | 0.14 | |||||||
Income from discontinued operations per weighted average common share — diluted | — | — | 0.71 | 0.02 | ||||||||||||
Net income per weighted average common share — diluted | $ | 0.98 | $ | 2.65 | $ | 0.49 | $ | 0.16 |
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Quarter Ended | ||||||||||||||||
2007 | ||||||||||||||||
December 31 | September 30 | June 30 | March 31 | |||||||||||||
(In millions, except per share data) | ||||||||||||||||
Operating revenues | $ | 1,382 | $ | 1,772 | $ | 1,536 | $ | 1,299 | ||||||||
Operating income | 320 | 546 | 427 | 267 | ||||||||||||
Income from continuing operations, net of income taxes | 100 | 265 | 143 | 61 | ||||||||||||
Income from discontinued operations, net of income taxes | 4 | 3 | 6 | 4 | ||||||||||||
Net income | $ | 104 | $ | 268 | $ | 149 | $ | 65 | ||||||||
Weighted average number of common shares outstanding — basic | 239 | 239 | 240 | 244 | ||||||||||||
Income from continuing operations per weighted average common share — basic | $ | 0.36 | $ | 1.05 | $ | 0.54 | $ | 0.19 | ||||||||
Income from discontinued operations per weighted average common share — basic | 0.02 | 0.02 | 0.02 | 0.02 | ||||||||||||
Net income per weighted average common share — basic | $ | 0.38 | $ | 1.07 | $ | 0.56 | $ | 0.21 | ||||||||
Weighted average number of common shares outstanding — diluted | 270 | 285 | 288 | 271 | ||||||||||||
Income from continuing operations per weighted average common share — diluted | $ | 0.34 | $ | 0.92 | $ | 0.49 | $ | 0.19 | ||||||||
Income from discontinued operations per weighted average common share — diluted | 0.01 | 0.01 | 0.02 | 0.01 | ||||||||||||
Net income per weighted average common share — diluted | $ | 0.35 | $ | 0.93 | $ | 0.51 | $ | 0.20 |
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Quarter Ended | ||||||||||||
September 30, 2008 | ||||||||||||
As reported | Adjustment | As revised | ||||||||||
Operating revenues | $ | 2,690 | $ | (78 | ) | $ | 2,612 | |||||
Operating income | 1,449 | (78 | ) | 1,371 | ||||||||
Income from continuing operations, net of income taxes | 784 | (50 | ) | 734 | ||||||||
Income from discontinued operations, net of income taxes | — | — | — | |||||||||
Net income | $ | 784 | $ | (50 | ) | $ | 734 | |||||
Weighted average number of common shares outstanding — basic | 235 | — | 235 | |||||||||
Income from continuing operations per weighted average common share — basic | $ | 3.28 | $ | (0.21 | ) | $ | 3.07 | |||||
Income from discontinued operations per weighted average common share — basic | — | — | — | |||||||||
Net income per weighted average common share — basic | $ | 3.28 | $ | (0.21 | ) | $ | 3.07 | |||||
Weighted average number of common shares outstanding — diluted | 277 | — | 277 | |||||||||
Income from continuing operations per weighted average common share — diluted | $ | 2.83 | $ | (0.18 | ) | $ | 2.65 | |||||
Income from discontinued operations per weighted average common share — diluted | — | — | — | |||||||||
Net income per weighted average common share — diluted | $ | 2.83 | $ | (0.18 | ) | $ | 2.65 |
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Note 28 — | Condensed Consolidating Financial Information |
Arthur Kill Power LLC | NRG Construction LLC | |
Astoria Gas Turbine Power LLC | NRG Devon Operations Inc. | |
Berrians I Gas Turbine Power LLC | NRG Dunkirk Operations, Inc. | |
Big Cajun II Unit 4 LLC | NRG El Segundo Operations Inc. | |
Cabrillo Power I LLC | NRG Generation Holdings, Inc. | |
Cabrillo Power II LLC | NRG Huntley Operations Inc. | |
Chickahominy River Energy Corp. | NRG International LLC | |
Commonwealth Atlantic Power LLC | NRG Kaufman LLC | |
Conemaugh Power LLC | NRG Mesquite LLC | |
Connecticut Jet Power LLC | NRG MidAtlantic Affiliate Services Inc. | |
Devon Power LLC | NRG Middletown Operations Inc. | |
Dunkirk Power LLC | NRG Montville Operations Inc. | |
Eastern Sierra Energy Company | NRG New Jersey Energy Sales LLC | |
El Segundo Power, LLC | NRG New Roads Holdings LLC | |
El Segundo Power II LLC | NRG North Central Operations, Inc. | |
GCP Funding Company LLC | NRG Northeast Affiliate Services Inc. | |
Hanover Energy Company | NRG Norwalk Harbor Operations Inc. | |
Hoffman Summit Wind Project LLC | NRG Operating Services Inc. | |
Huntley IGCC LLC | NRG Oswego Harbor Power Operations Inc. | |
Huntley Power LLC | NRG Power Marketing LLC | |
Indian River IGCC LLC | NRG Rocky Road LLC | |
Indian River Operations Inc. | NRG Saguaro Operations Inc. | |
Indian River Power LLC | NRG South Central Affiliate Services Inc. | |
James River Power LLC | NRG South Central Generating LLC | |
Kaufman Cogen LP | NRG South Central Operations Inc. | |
Keystone Power LLC | NRG South Texas LP | |
Lake Erie Properties Inc. | NRG Texas LLC | |
Louisiana Generating LLC | NRG Texas Power LLC | |
Middletown Power LLC | NRG West Coast LLC | |
Montville IGCC LLC | NRG Western Affiliate Services Inc. | |
Montville Power LLC | Oswego Harbor Power LLC | |
NEO Chester-Gen LLC | Padoma Wind Power, LLC | |
NEO Corporation | Saguaro Power LLC | |
NEO Freehold-Gen LLC | San Juan Mesa Wind Project II, LLC | |
NEO Power Services Inc. | Somerset Operations Inc. | |
New Genco GP LLC | Somerset Power LLC |
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Norwalk Power LLC | Texas Genco Financing Corp. | |
NRG Affiliate Services Inc. | Texas Genco GP, LLC | |
NRG Arthur Kill Operations Inc. | Texas Genco Holdings, Inc. | |
NRG Asia-Pacific Ltd. | Texas Genco LP, LLC | |
NRG Astoria Gas Turbine Operations Inc. | Texas Genco Operating Services, LLC | |
NRG Bayou Cove LLC | Texas Genco Services, LP | |
NRG Cabrillo Power Operations Inc. | Vienna Operations, Inc. | |
NRG Cadillac Operations Inc. | Vienna Power LLC | |
NRG California Peaker Operations LLC | WCP (Generation) Holdings LLC | |
NRG Cedar Bayou Development Company LLC | West Coast Power LLC | |
NRG Connecticut Affiliate Services Inc. |
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CONSOLIDATING STATEMENTS OF OPERATIONS
Guarantor | Non-Guarantor | Consolidated | ||||||||||||||||||
Subsidiaries | Subsidiaries | NRG Energy, Inc. | Eliminations(a) | Balance | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||
Total operating revenues | $ | 6,504 | $ | 405 | $ | — | $ | (24 | ) | $ | 6,885 | |||||||||
Operating Costs and Expenses | ||||||||||||||||||||
Cost of operations | 3,321 | 303 | — | (26 | ) | 3,598 | ||||||||||||||
Depreciation and amortization | 618 | 27 | 4 | — | 649 | |||||||||||||||
General and administrative | 64 | 14 | 241 | — | 319 | |||||||||||||||
Development costs | (1 | ) | 7 | 40 | — | 46 | ||||||||||||||
Total operating costs and expenses | 4,002 | 351 | 285 | (26 | ) | 4,612 | ||||||||||||||
Operating Income/(Loss) | 2,502 | 54 | (285 | ) | 2 | 2,273 | ||||||||||||||
Other Income/(Expense) | ||||||||||||||||||||
Equity in earnings of consolidated subsidiaries | 276 | — | 1,601 | (1,877 | ) | — | ||||||||||||||
Equity in earnings of unconsolidated affiliates | (2 | ) | 61 | — | — | 59 | ||||||||||||||
Other income/(expense), net | 23 | 11 | (15 | ) | (2 | ) | 17 | |||||||||||||
Interest expense | (183 | ) | (114 | ) | (323 | ) | — | (620 | ) | |||||||||||
Total other income/(expense) | 114 | (42 | ) | 1,263 | (1,879 | ) | (544 | ) | ||||||||||||
Income From Continuing Operations Before Income Taxes | 2,616 | 12 | 978 | (1,877 | ) | 1,729 | ||||||||||||||
Income tax expense/(benefit) | 1,001 | 19 | (307 | ) | — | 713 | ||||||||||||||
Income From Continuing Operations | 1,615 | (7 | ) | 1,285 | (1,877 | ) | 1,016 | |||||||||||||
Income(loss) from discontinued operations, net of income taxes | — | 269 | (97 | ) | — | 172 | ||||||||||||||
Net Income | $ | 1,615 | $ | 262 | $ | 1,188 | $ | (1,877 | ) | $ | 1,188 | |||||||||
(a) | All significant intercompany transactions have been eliminated in consolidation. |
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CONSOLIDATING BALANCE SHEETS
Guarantor | Non-Guarantor | Consolidated | ||||||||||||||||||
Subsidiaries | Subsidiaries | NRG Energy, Inc. | Eliminations(a) | Balance | ||||||||||||||||
(In millions) | ||||||||||||||||||||
ASSETS | ||||||||||||||||||||
Current Assets | ||||||||||||||||||||
Cash and cash equivalents | $ | (2 | ) | $ | 159 | $ | 1,337 | $ | — | $ | 1,494 | |||||||||
Funds deposited by counterparties | — | — | 754 | — | 754 | |||||||||||||||
Restricted cash | 7 | 9 | — | — | 16 | |||||||||||||||
Accounts receivable-trade, net | 422 | 42 | — | — | 464 | |||||||||||||||
Inventory | 443 | 12 | — | — | 455 | |||||||||||||||
Derivative instruments valuation | 4,600 | — | — | — | 4,600 | |||||||||||||||
Cash collateral paid in support of energy risk management activities | 494 | — | — | — | 494 | |||||||||||||||
Prepayments and other current assets | 130 | 37 | 278 | (230 | ) | 215 | ||||||||||||||
Total current assets | 6,094 | 259 | 2,369 | (230 | ) | 8,492 | ||||||||||||||
Net Property, Plant and Equipment | 10,725 | 791 | 29 | — | 11,545 | |||||||||||||||
Other Assets | ||||||||||||||||||||
Investment in subsidiaries | 651 | 18 | 11,941 | (12,610 | ) | — | ||||||||||||||
Equity investments in affiliates | 26 | 464 | — | — | 490 | |||||||||||||||
Capital leases and note receivable, less current portion | 598 | 435 | 3,177 | (3,775 | ) | 435 | ||||||||||||||
Goodwill | 1,718 | — | — | — | 1,718 | |||||||||||||||
Intangible assets, net | 797 | 16 | 2 | — | 815 | |||||||||||||||
Nuclear decommissioning trust fund | 303 | — | — | — | 303 | |||||||||||||||
Derivative instruments valuation | 870 | — | 15 | — | 885 | |||||||||||||||
Other non-current assets | 9 | 4 | 112 | — | 125 | |||||||||||||||
Total other assets | 4,972 | 937 | 15,247 | (16,385 | ) | 4,771 | ||||||||||||||
Total Assets | $ | 21,791 | $ | 1,987 | $ | 17,645 | $ | (16,615 | ) | $ | 24,808 | |||||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||||||||||
Current Liabilities | ||||||||||||||||||||
Current portion of long-term debt and capital leases | $ | 67 | $ | 235 | $ | 229 | $ | (67 | ) | $ | 464 | |||||||||
Accounts payable — trade | (1,302 | ) | 429 | 1,324 | — | 451 | ||||||||||||||
Derivative instruments valuation | 3,976 | 3 | 2 | — | 3,981 | |||||||||||||||
Deferred income taxes | 503 | 31 | (333 | ) | — | 201 | ||||||||||||||
Cash collateral received in support of energy risk management activities | 760 | — | — | — | 760 | |||||||||||||||
Accrued expenses and other current liabilities | 507 | 48 | 333 | (164 | ) | 724 | ||||||||||||||
Total current liabilities | 4,511 | 746 | 1,555 | (231 | ) | 6,581 | ||||||||||||||
Other Liabilities | ||||||||||||||||||||
Long-term debt and capital leases | 2,730 | 1,021 | 7,728 | (3,775 | ) | 7,704 | ||||||||||||||
Nuclear decommissioning reserve | 284 | — | — | — | 284 | |||||||||||||||
Nuclear decommissioning trust liability | 218 | — | — | — | 218 | |||||||||||||||
Deferred income taxes | 705 | (187 | ) | 672 | — | 1,190 | ||||||||||||||
Derivative instruments valuation | 348 | 46 | 114 | — | 508 | |||||||||||||||
Out-of-market contracts | 291 | — | — | — | 291 | |||||||||||||||
Other non-current liabilities | 405 | 44 | 220 | — | 669 | |||||||||||||||
Total non-current liabilities | 4,981 | 924 | 8,734 | (3,775 | ) | 10,864 | ||||||||||||||
Total liabilities | 9,492 | 1,670 | 10,289 | (4,006 | ) | 17,445 | ||||||||||||||
Minority Interest | 7 | — | — | — | 7 | |||||||||||||||
3.625% Preferred Stock | — | — | 247 | — | 247 | |||||||||||||||
Stockholders’ Equity | 12,292 | 317 | 7,109 | (12,609 | ) | 7,109 | ||||||||||||||
Total Liabilities and Stockholders’ Equity | $ | 21,791 | $ | 1,987 | $ | 17,645 | $ | (16,615 | ) | $ | 24,808 | |||||||||
(a) | All significant intercompany transactions have been eliminated in consolidation. |
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CONSOLIDATING STATEMENTS OF CASH FLOWS
NRG | ||||||||||||||||||||
Guarantor | Non-Guarantor | Energy, | Consolidated | |||||||||||||||||
Subsidiaries | Subsidiaries | Inc. | Eliminations(a) | Balance | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Cash Flows from Operating Activities | ||||||||||||||||||||
Net income | $ | 1,615 | $ | 262 | $ | 1,188 | $ | (1,877 | ) | $ | 1,188 | |||||||||
Adjustments to reconcile net income to net cash provided by operating activities | ||||||||||||||||||||
Distributions in excess/(less than) equity in earnings of unconsolidated affiliates | (274 | ) | (46 | ) | (1,601 | ) | 1,877 | (44 | ) | |||||||||||
Depreciation and amortization | 618 | 27 | 4 | — | 649 | |||||||||||||||
Amortization of nuclear fuel | 39 | — | — | — | 39 | |||||||||||||||
Amortization and write-off of deferred financing costs and debt discount/premiums | — | 7 | 22 | — | 29 | |||||||||||||||
Amortization of intangibles and out-of-market contracts | (270 | ) | — | — | — | (270 | ) | |||||||||||||
Amortization of unearned equity compensation | — | — | 26 | — | 26 | |||||||||||||||
Loss on disposals and sales of assets | 25 | — | — | — | 25 | |||||||||||||||
Impairment charges and asset write downs | — | — | 23 | — | 23 | |||||||||||||||
Changes in derivatives | (482 | ) | (2 | ) | — | — | (484 | ) | ||||||||||||
Changes in deferred income taxes and liability for unrecognized tax benefits | 312 | (16 | ) | 466 | — | 762 | ||||||||||||||
Gain on sale of discontinued operations | — | (273 | ) | — | — | (273 | ) | |||||||||||||
Gain on sale of emission allowances | (51 | ) | — | — | — | (51 | ) | |||||||||||||
Change in nuclear decommissioning trust liability | 34 | — | — | — | 34 | |||||||||||||||
Changes in collateral deposits supporting energy risk management activities | (417 | ) | — | — | — | (417 | ) | |||||||||||||
Cash provided/(used) by changes in other working capital, net of disposition affects | 745 | 88 | (635 | ) | — | 198 | ||||||||||||||
Net Cash Provided/(Used) by Operating Activities | 1,894 | 47 | (507 | ) | — | 1,434 | ||||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||
Intercompany (loans to)/receipts from subsidiaries | (238 | ) | — | 696 | (458 | ) | — | |||||||||||||
Capital expenditures | (597 | ) | (294 | ) | (8 | ) | — | (899 | ) | |||||||||||
Decrease in restricted cash | (6 | ) | 19 | — | — | 13 | ||||||||||||||
Decrease in notes receivable | — | 45 | (35 | ) | — | 10 | ||||||||||||||
Purchases of emission allowances | (8 | ) | — | — | — | (8 | ) | |||||||||||||
Proceeds from sale of emission allowances | 75 | — | — | — | 75 | |||||||||||||||
Investments in nuclear decommissioning trust fund securities | (616 | ) | — | — | — | (616 | ) | |||||||||||||
Proceeds from sales of nuclear decommissioning trust fund securities | 582 | — | — | — | 582 | |||||||||||||||
Proceeds from sale of assets | 14 | — | — | — | 14 | |||||||||||||||
Equity investment in unconsolidated affiliate | — | (84 | ) | — | — | (84 | ) | |||||||||||||
Proceeds from sale of discontinued operations, net of cash divested | — | (59 | ) | 300 | — | 241 | ||||||||||||||
Net Cash Provided/(Used) by Investing Activities | (794 | ) | (373 | ) | 953 | (458 | ) | (672 | ) | |||||||||||
Cash Flows from Financing Activities | ||||||||||||||||||||
(Payments)/proceeds from intercompany loans | (1,059 | ) | 315 | 286 | 458 | — | ||||||||||||||
Payment of dividends to preferred stockholders | — | — | (55 | ) | — | (55 | ) | |||||||||||||
Payment of financing element of acquired derivatives | (43 | ) | — | — | — | (43 | ) | |||||||||||||
Payment for treasury stock | — | — | (185 | ) | — | (185 | ) | |||||||||||||
Proceeds from sale of minority interest in subsidiary | — | 50 | — | — | 50 | |||||||||||||||
Proceeds from issuance of common stock, net of issuance costs | — | — | 9 | — | 9 | |||||||||||||||
Proceeds from issuance of long-term debt | — | 20 | — | 20 | ||||||||||||||||
Payment of deferred debt issuance costs | — | (2 | ) | (2 | ) | — | (4 | ) | ||||||||||||
Payments of short and long-term debt | — | (60 | ) | (174 | ) | — | (234 | ) | ||||||||||||
Net Cash Provided/(Used) by Financing Activities | (1,102 | ) | 323 | (121 | ) | 458 | (442 | ) | ||||||||||||
Change in cash from discontinued operations | — | 43 | — | — | 43 | |||||||||||||||
Effect of exchange rate changes on cash and cash equivalents | — | (1 | ) | — | — | (1 | ) | |||||||||||||
Net Increase/(Decrease) in Cash and Cash Equivalents | (2 | ) | 39 | �� | 325 | — | 362 | |||||||||||||
Cash and Cash Equivalents at Beginning of Period | — | 120 | 1,012 | — | 1,132 | |||||||||||||||
Cash and Cash Equivalents at End of Period | $ | (2 | ) | $ | 159 | $ | 1,337 | $ | — | $ | 1,494 | |||||||||
(a) | All significant intercompany transactions have been eliminated in consolidation. |
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CONSOLIDATING STATEMENTS OF OPERATIONS
Guarantor | Non-Guarantor | Consolidated | ||||||||||||||||||
Subsidiaries | Subsidiaries | NRG Energy, Inc. | Eliminations(a) | Balance | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||
Total operating revenues | $ | 5,614 | $ | 375 | $ | — | $ | — | $ | 5,989 | ||||||||||
Operating Costs and Expenses | ||||||||||||||||||||
Cost of operations | 3,130 | 248 | — | — | 3,378 | |||||||||||||||
Depreciation and amortization | 630 | 24 | 4 | — | 658 | |||||||||||||||
General and administrative | 102 | 18 | 189 | — | 309 | |||||||||||||||
Development costs | 66 | 2 | 33 | — | 101 | |||||||||||||||
Total operating costs and expenses | 3,928 | 292 | 226 | — | 4,446 | |||||||||||||||
Gain/(loss) on sale of assets | 18 | — | (1 | ) | — | 17 | ||||||||||||||
Operating Income/(Loss) | 1,704 | 83 | (227 | ) | — | 1,560 | ||||||||||||||
Other Income/(Expense) | ||||||||||||||||||||
Equity in earnings of consolidated subsidiaries | 204 | — | 986 | (1,190 | ) | — | ||||||||||||||
Equity in earnings of unconsolidated affiliates | (3 | ) | 57 | — | — | 54 | ||||||||||||||
Gain on sale of equity method investments | — | 1 | — | — | 1 | |||||||||||||||
Other income, net | 9 | 13 | 33 | — | 55 | |||||||||||||||
Refinancing expenses | — | — | (35 | ) | — | (35 | ) | |||||||||||||
Interest expense | (250 | ) | (64 | ) | (375 | ) | — | (689 | ) | |||||||||||
Total other income/(expense) | (40 | ) | 7 | 609 | (1,190 | ) | (614 | ) | ||||||||||||
Income From Continuing Operations Before Income Taxes | 1,664 | 90 | 382 | (1,190 | ) | 946 | ||||||||||||||
Income tax expense/(benefit) | 576 | 5 | (204 | ) | — | 377 | ||||||||||||||
Income From Continuing Operations | 1,088 | 85 | 586 | (1,190 | ) | 569 | ||||||||||||||
Income from discontinued operations, net of income taxes | — | 17 | — | — | 17 | |||||||||||||||
Net Income | $ | 1,088 | $ | 102 | $ | 586 | $ | (1,190 | ) | $ | 586 | |||||||||
(a) | All significant intercompany transactions have been eliminated in consolidation. |
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CONSOLIDATING BALANCE SHEETS
Guarantor | Non-Guarantor | Consolidated | ||||||||||||||||||
Subsidiaries | Subsidiaries | NRG Energy, Inc. | Eliminations(a) | Balance | ||||||||||||||||
(In millions) | ||||||||||||||||||||
ASSETS | ||||||||||||||||||||
Current Assets | ||||||||||||||||||||
Cash and cash equivalents | $ | — | $ | 120 | $ | 1,012 | $ | — | $ | 1,132 | ||||||||||
Restricted cash | 1 | 28 | — | — | 29 | |||||||||||||||
Accounts receivable-trade, net | 445 | 37 | — | — | 482 | |||||||||||||||
Inventory | 439 | 12 | — | — | 451 | |||||||||||||||
Deferred income taxes | 139 | (18 | ) | 3 | — | 124 | ||||||||||||||
Derivative instruments valuation | 1,034 | — | — | — | 1,034 | |||||||||||||||
Cash collateral paid in support of energy risk management activities | 85 | — | — | — | 85 | |||||||||||||||
Prepayments and other current assets | 97 | 34 | 195 | (152 | ) | 174 | ||||||||||||||
Current assets — discontinued operations | — | 51 | — | — | 51 | |||||||||||||||
Total current assets | 2,240 | 264 | 1,210 | (152 | ) | 3,562 | ||||||||||||||
Net Property, Plant and Equipment | 10,828 | 470 | 22 | — | 11,320 | |||||||||||||||
Other Assets | ||||||||||||||||||||
Investment in subsidiaries | 610 | — | 9,787 | (10,397 | ) | — | ||||||||||||||
Equity investments in affiliates | 28 | 397 | — | — | 425 | |||||||||||||||
Capital leases and notes receivable, less current portion | 360 | 491 | 3,779 | (4,139 | ) | 491 | ||||||||||||||
Goodwill | 1,786 | — | — | — | 1,786 | |||||||||||||||
Intangible assets, net | 859 | 14 | — | — | 873 | |||||||||||||||
Nuclear decommissioning trust fund | 384 | — | — | — | 384 | |||||||||||||||
Derivative instruments valuation | 150 | — | — | — | 150 | |||||||||||||||
Other non-current assets | 25 | 1 | 164 | — | 190 | |||||||||||||||
Non-current assets — discontinued operations | — | 93 | — | — | 93 | |||||||||||||||
Total other assets | 4,202 | 996 | 13,730 | (14,536 | ) | 4,392 | ||||||||||||||
Total Assets | $ | 17,270 | $ | 1,730 | $ | 14,962 | $ | (14,688 | ) | $ | 19,274 | |||||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||||||||||
Current Liabilities | ||||||||||||||||||||
Current portion of long-term debt and capital leases | $ | 83 | $ | 282 | $ | 184 | $ | (83 | ) | $ | 466 | |||||||||
Accounts payable — trade | (695 | ) | 348 | 731 | — | 384 | ||||||||||||||
Derivative instruments valuation | 916 | 1 | — | — | 917 | |||||||||||||||
Cash collateral received in support of energy risk management activities | 14 | — | — | — | 14 | |||||||||||||||
Accrued expenses and other current liabilities | 321 | 62 | 145 | (69 | ) | 459 | ||||||||||||||
Current liabilities — discontinued operations | — | 37 | — | — | 37 | |||||||||||||||
Total current liabilities | 639 | 730 | 1,060 | (152 | ) | 2,277 | ||||||||||||||
Other Liabilities | ||||||||||||||||||||
Long-term debt and capital leases | 3,773 | 571 | 7,690 | (4,139 | ) | 7,895 | ||||||||||||||
Nuclear decommissioning reserve | 307 | — | — | — | 307 | |||||||||||||||
Nuclear decommissioning trust liability | 326 | — | — | — | 326 | |||||||||||||||
Deferred income taxes | 598 | (138 | ) | 383 | — | 843 | ||||||||||||||
Derivative instruments valuation | 690 | 16 | 53 | — | 759 | |||||||||||||||
Out-of-market contracts | 628 | — | — | — | 628 | |||||||||||||||
Other non-current liabilities | 377 | 10 | 25 | — | 412 | |||||||||||||||
Non-current liabilities — discontinued operations | — | 76 | — | — | 76 | |||||||||||||||
Total non-current liabilities | 6,699 | 535 | 8,151 | (4,139 | ) | 11,246 | ||||||||||||||
Total liabilities | 7,338 | 1,265 | 9,211 | (4,291 | ) | 13,523 | ||||||||||||||
3.625% Preferred Stock | — | — | 247 | — | 247 | |||||||||||||||
Stockholders’ Equity | 9,932 | 465 | 5,504 | (10,397 | ) | 5,504 | ||||||||||||||
Total Liabilities and Stockholders’ Equity | $ | 17,270 | $ | 1,730 | $ | 14,962 | $ | (14,688 | ) | $ | 19,274 | |||||||||
(a) | All significant intercompany transactions have been eliminated in consolidation. |
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Guarantor | Non-Guarantor | Consolidated | ||||||||||||||||||
Subsidiaries | Subsidiaries | NRG Energy, Inc. | Eliminations(a) | Balance | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Cash Flows from Operating Activities | ||||||||||||||||||||
Net income | $ | 1,088 | $ | 102 | $ | 586 | $ | (1,190 | ) | $ | 586 | |||||||||
Adjustments to reconcile net income to net cash provided/(used) by operating activities | ||||||||||||||||||||
Distributions in excess/(less than) equity in earnings of unconsolidated affiliates | 101 | (36 | ) | (684 | ) | 586 | (33 | ) | ||||||||||||
Depreciation and amortization | 630 | 27 | 4 | — | 661 | |||||||||||||||
Amortization of nuclear fuel | 58 | — | — | — | 58 | |||||||||||||||
Amortization and write-off of deferred financing costs and debt discount/premiums | — | 6 | 60 | — | 66 | |||||||||||||||
Amortization of intangibles and out-of-market contracts | (160 | ) | 4 | — | — | (156 | ) | |||||||||||||
Amortization of unearned equity compensation | — | — | 19 | — | 19 | |||||||||||||||
Gains on sale of equity method investments | — | (1 | ) | — | — | (1 | ) | |||||||||||||
(Gain)/loss on sale assets | (18 | ) | — | 1 | — | (17 | ) | |||||||||||||
Impairment charges and asset write downs | 9 | — | 11 | — | 20 | |||||||||||||||
Changes in derivatives | 77 | — | — | — | 77 | |||||||||||||||
Changes in deferred income taxes | 112 | (31 | ) | 271 | — | 352 | ||||||||||||||
Gain on sale of emission allowances | (30 | ) | (1 | ) | — | — | (31 | ) | ||||||||||||
Change in nuclear decommissioning trust liability | 32 | — | — | — | 32 | |||||||||||||||
Changes in collateral deposits supporting energy risk management activities | (125 | ) | — | — | — | (125 | ) | |||||||||||||
Cash provided/(used) by changes in other working capital, net of disposition affects | 218 | 96 | (305 | ) | — | 9 | ||||||||||||||
Net Cash Provided/(Used) by Operating Activities | 1,992 | 166 | (37 | ) | (604 | ) | 1,517 | |||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||
Intercompany loans to subsidiaries | 655 | — | 2,109 | (2,764 | ) | — | ||||||||||||||
Capital expenditures | (389 | ) | (84 | ) | (8 | ) | — | (481 | ) | |||||||||||
Decrease in restricted cash, net | — | 12 | — | — | 12 | |||||||||||||||
Decrease in notes receivable | — | 34 | — | — | 34 | |||||||||||||||
Decrease in trust fund balances | 19 | — | — | — | 19 | |||||||||||||||
Purchases of emission allowances | (161 | ) | — | — | — | (161 | ) | |||||||||||||
Proceeds from sale of emission allowances | 271 | 1 | — | — | 272 | |||||||||||||||
Investments in nuclear decommissioning trust fund securities | (265 | ) | — | — | — | (265 | ) | |||||||||||||
Proceeds from sales of nuclear decommissioning trust fund securities | 233 | — | — | — | 233 | |||||||||||||||
Proceeds from sale of assets | — | 2 | — | — | 2 | |||||||||||||||
Purchase of securities | — | — | (49 | ) | — | (49 | ) | |||||||||||||
Proceeds from sale of discontinued operations and assets, net of cash divested | 29 | — | 28 | — | 57 | |||||||||||||||
Net Cash Provided/(Used) by Investing Activities | 392 | (35 | ) | 2,080 | (2,764 | ) | (327 | ) | ||||||||||||
Cash Flows from Financing Activities | ||||||||||||||||||||
Payment of dividends to preferred stockholders | — | — | (55 | ) | — | (55 | ) | |||||||||||||
Payment for treasury stock | — | — | (353 | ) | — | (353 | ) | |||||||||||||
Payments from intercompany loans | (2,101 | ) | (38 | ) | (625 | ) | 2,764 | — | ||||||||||||
Payments from intercompany dividends | (302 | ) | (302 | ) | — | 604 | — | |||||||||||||
Proceeds from issuance of common stock, net of issuance costs | — | — | 7 | — | 7 | |||||||||||||||
Proceeds from issuance of long-term debt | — | — | 1,411 | — | 1,411 | |||||||||||||||
Payment of deferred debt issuance costs | — | — | (5 | ) | — | (5 | ) | |||||||||||||
Payments of short and long-term debt | (1 | ) | (64 | ) | (1,754 | ) | — | (1,819 | ) | |||||||||||
Net Cash Provided/(Used) by Financing Activities | (2,404 | ) | (404 | ) | (1,374 | ) | 3,368 | (814 | ) | |||||||||||
Change in cash from discontinued operations | — | (25 | ) | — | — | (25 | ) | |||||||||||||
Effect of exchange rate changes on cash and cash equivalents | — | 4 | — | — | 4 | |||||||||||||||
Net Increase/(Decrease) in Cash and Cash Equivalents | (20 | ) | (294 | ) | 669 | — | 355 | |||||||||||||
Cash and Cash Equivalents at Beginning of Period | 20 | 414 | 343 | — | 777 | |||||||||||||||
Cash and Cash Equivalents at End of Period | $ | — | $ | 120 | $ | 1,012 | $ | — | $ | 1,132 | ||||||||||
(a) | All significant intercompany transactions have been eliminated in consolidation. |
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Guarantor | Non-Guarantor | NRG | Consolidated | |||||||||||||||||
Subsidiaries | Subsidiaries | Energy, Inc. | Eliminations(a) | Balance | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Operating Revenues | ||||||||||||||||||||
Total operating revenues | $ | 5,282 | $ | 303 | $ | — | $ | — | $ | 5,585 | ||||||||||
Operating Costs and Expenses | ||||||||||||||||||||
Cost of operations | 3,038 | 225 | 2 | — | 3,265 | |||||||||||||||
Depreciation and amortization | 562 | 23 | 5 | — | 590 | |||||||||||||||
General and administrative | 82 | 14 | 180 | — | 276 | |||||||||||||||
Development costs | 32 | — | 4 | — | 36 | |||||||||||||||
Total operating costs and expenses | 3,714 | 262 | 191 | — | 4,167 | |||||||||||||||
Operating Income/(Loss) | 1,568 | 41 | (191 | ) | — | 1,418 | ||||||||||||||
Other Income/(Expense) | ||||||||||||||||||||
Equity in earnings of consolidated subsidiaries | 134 | — | 996 | (1,130 | ) | — | ||||||||||||||
Equity in earnings of unconsolidated affiliates | 2 | 58 | — | — | 60 | |||||||||||||||
Gains/(losses) on sales of equity method investments | (5 | ) | 13 | — | — | 8 | ||||||||||||||
Other income, net | 20 | 115 | 41 | (20 | ) | 156 | ||||||||||||||
Refinancing expenses | — | — | (187 | ) | — | (187 | ) | |||||||||||||
Interest expense | (232 | ) | (56 | ) | (322 | ) | 20 | (590 | ) | |||||||||||
Total other income/(expense) | (81 | ) | 130 | 528 | (1,130 | ) | (553 | ) | ||||||||||||
Income From Continuing Operations Before Income Taxes | 1,487 | 171 | 337 | (1,130 | ) | 865 | ||||||||||||||
Income tax expense | 549 | 42 | (269 | ) | — | 322 | ||||||||||||||
Income From Continuing Operations | 938 | 129 | 606 | (1,130 | ) | 543 | ||||||||||||||
Income from discontinued operations, net of income taxes | — | 63 | 15 | — | 78 | |||||||||||||||
Net Income | $ | 938 | $ | 192 | $ | 621 | $ | (1,130 | ) | $ | 621 | |||||||||
(a) | All significant intercompany transactions have been eliminated in consolidation. |
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Guarantor | Non-Guarantor | Consolidated | ||||||||||||||||||
Subsidiaries | Subsidiaries | NRG Energy, Inc. | Eliminations(a) | Balance | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Cash Flows from Operating Activities | ||||||||||||||||||||
Net income | $ | 938 | $ | 192 | $ | 621 | $ | (1,130 | ) | $ | 621 | |||||||||
Adjustments to reconcile net income to net cash provided/(used) by operating activities | ||||||||||||||||||||
Distributions in excess/(less than) equity in earnings of unconsolidated affiliates | (136 | ) | (31 | ) | (996 | ) | 1,130 | (33 | ) | |||||||||||
Depreciation and amortization of nuclear fuel | 609 | 35 | 10 | — | 654 | |||||||||||||||
Amortization and write-of of deferred financing costs and debt discount/premiums | — | 6 | 73 | — | 79 | |||||||||||||||
Amortization of intangibles and out-of-market contracts | (487 | ) | (3 | ) | — | — | (490 | ) | ||||||||||||
Amortization of unearned equity compensation | — | — | 14 | — | 14 | |||||||||||||||
Write down and gains on sale of equity method investments | 5 | (13 | ) | — | — | (8 | ) | |||||||||||||
Loss on sale of equipment | 10 | — | — | — | 10 | |||||||||||||||
Changes in derivatives | (151 | ) | 2 | — | — | (149 | ) | |||||||||||||
Changes in deferred income taxes | 474 | 19 | (166 | ) | — | 327 | ||||||||||||||
Gain on legal settlement | — | (67 | ) | — | — | (67 | ) | |||||||||||||
Gain on sale of discontinued operations | — | (71 | ) | (5 | ) | — | (76 | ) | ||||||||||||
Gain on sale of emission allowances | (64 | ) | — | — | — | (64 | ) | |||||||||||||
Change in nuclear decommissioning trust liability | 12 | — | — | — | 12 | |||||||||||||||
Changes in collateral deposits supporting energy risk management activities | 454 | — | — | — | 454 | |||||||||||||||
Settlement of out-of-market power contracts | (1,073 | ) | — | — | — | (1,073 | ) | |||||||||||||
Cash provided/(used) by changes in other working capital, net of acquisition and disposition affects | (557 | ) | 216 | 538 | — | 197 | ||||||||||||||
Net Cash Provided by Operating Activities | 34 | 285 | 89 | — | 408 | |||||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||
I/C loans to subsidiaries | (939 | ) | — | (4,106 | ) | 5,045 | — | |||||||||||||
Acquisition of Texas Genco, WCP and Padoma, net of cash acquired | — | — | (4,333 | ) | — | (4,333 | ) | |||||||||||||
Capital expenditures | (195 | ) | (21 | ) | (5 | ) | — | (221 | ) | |||||||||||
Decrease in restricted cash, net | 2 | 4 | — | — | 6 | |||||||||||||||
Decrease in notes receivable | — | 27 | — | — | 27 | |||||||||||||||
Purchases of emission allowances | (135 | ) | — | — | — | (135 | ) | |||||||||||||
Proceeds from sale of emission allowances | 146 | — | — | — | 146 | |||||||||||||||
Investments in nuclear decommissioning trust fund securities | (227 | ) | — | — | — | (227 | ) | |||||||||||||
Proceeds from sales of nuclear decommissioning trust fund securities | 214 | — | — | — | 214 | |||||||||||||||
Proceeds from sale of investments | 53 | 33 | — | — | 86 | |||||||||||||||
Proceeds from sale of discontinued operations | — | 239 | 22 | — | 261 | |||||||||||||||
Net Cash Provided/(Used) by Investing Activities | (1,081 | ) | 282 | (8,422 | ) | 5,045 | (4,176 | ) | ||||||||||||
Cash Flows from Financing Activities | ||||||||||||||||||||
Payment of dividends to preferred stockholders | — | — | (50 | ) | — | (50 | ) | |||||||||||||
Payment of financing element of acquired derivatives | (296 | ) | — | — | — | (296 | ) | |||||||||||||
Payment for treasury stock | — | (500 | ) | (232 | ) | — | (732 | ) | ||||||||||||
Funded letter of credit | — | — | 350 | — | 350 | |||||||||||||||
Proceeds from Intercompany loans | 4,106 | — | 939 | (5,045 | ) | — | ||||||||||||||
Proceeds from issuance of common stock, net | — | — | 986 | — | 986 | |||||||||||||||
Proceeds from issuance of preferred shares, net | — | — | 486 | — | 486 | |||||||||||||||
Proceeds from issuance of long-term debt | — | 333 | 8,286 | — | 8,619 | |||||||||||||||
Payment of deferred debt issuance costs | — | — | (199 | ) | — | (199 | ) | |||||||||||||
Payments of short and long-term debt | (2,736 | ) | (62 | ) | (2,313 | ) | — | (5,111 | ) | |||||||||||
Net Cash Provided/(Used) by Financing Activities | 1,074 | (229 | ) | 8,253 | (5,045 | ) | 4,053 | |||||||||||||
Change in cash from discontinued operations | — | 1 | 1 | — | 2 | |||||||||||||||
Effect of exchange rate changes on cash and cash equivalents | — | 4 | — | — | 4 | |||||||||||||||
Net Increase/(decrease) in Cash and Cash Equivalents | 27 | 343 | (79 | ) | — | 291 | ||||||||||||||
Cash and Cash Equivalents at Beginning of Period | (7 | ) | 71 | 422 | — | 486 | ||||||||||||||
Cash and Cash Equivalents at End of Period | $ | 20 | $ | 414 | $ | 343 | $ | — | $ | 777 | ||||||||||
(a) | All significant intercompany transactions have been eliminated in consolidation. |
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Balance at | Charged to | Charged to | ||||||||||||||||||
Beginning of | Costs and | Other | Additions/ | Balance at | ||||||||||||||||
Period | Expenses | Accounts | (Deductions) | End of Period | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Allowance for doubtful accounts, deducted from accounts receivable | ||||||||||||||||||||
Year ended December 31, 2008 | $ | 1 | $ | 2 | $ | — | $ | — | $ | 3 | ||||||||||
Year ended December 31, 2007 | $ | 1 | $ | — | $ | — | $ | — | $ | 1 | ||||||||||
Year ended December 31, 2006 | $ | 2 | $ | — | $ | — | $ | (1 | ) | $ | 1 | |||||||||
Income tax valuation allowance, deducted from deferred tax assets | ||||||||||||||||||||
Year ended December 31, 2008 | $ | 539 | $ | (12 | ) | $ | (6 | ) | $ | (162 | ) | $ | 359 | |||||||
Year ended December 31, 2007 | $ | 581 | $ | 6 | $ | 8 | $ | (56 | ) | $ | 539 | |||||||||
Year ended December 31, 2006 | $ | 836 | $ | (10 | ) | $ | (81 | ) | $ | (164 | ) | $ | 581 |
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/s/ David W. Crane |
230
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Signature | Title | Date | ||||
/s/ David W. Crane David W. Crane | President, Chief Executive Officer and Director | February 12, 2009 | ||||
/s/ Howard E. Cosgrove Howard E. Cosgrove | Chairman of the Board | February 12, 2009 | ||||
/s/ John F. Chlebowski John F. Chlebowski | Director | February 12, 2009 | ||||
/s/ Lawrence S. Coben Lawrence S. Coben | Director | February 12, 2009 | ||||
/s/ Stephen L. Cropper Stephen L. Cropper | Director | February 12, 2009 | ||||
/s/ William E. Hantke William E. Hantke | Director | February 12, 2009 | ||||
/s/ Paul W. Hobby Paul W. Hobby | Director | February 12, 2009 | ||||
/s/ Kathleen A. McGinty Kathleen A. McGinty | Director | February 12, 2009 | ||||
/s/ Anne C. Schaumburg Anne C. Schaumburg | Director | February 12, 2009 | ||||
/s/ Herbert H. Tate Herbert H. Tate | Director | February 12, 2009 | ||||
/s/ Thomas H. Weidemeyer Thomas H. Weidemeyer | Director | February 12, 2009 | ||||
/s/ Walter R. Young Walter R. Young | Director | February 12, 2009 |
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2 | .1 | Third Amended Joint Plan of Reorganization of NRG Energy, Inc., NRG Power Marketing, Inc., NRG Capital LLC, NRG Finance Company I LLC, and NRGenerating Holdings (No. 23) B.V.(5) | ||
2 | .2 | First Amended Joint Plan of Reorganization of NRG Northeast Generating LLC (and certain of its subsidiaries), NRG South Central Generating (and certain of its subsidiaries) and Berrians I Gas Turbine Power LLC.(5) | ||
2 | .3 | Acquisition Agreement, dated as of September 30, 2005, by and among NRG Energy, Inc., Texas Genco LLC and the Direct and Indirect Owners of Texas Genco LLC.(11) | ||
3 | .1 | Amended and Restated Certificate of Incorporation.(16) | ||
3 | .2 | Amended and Restated By-Laws.(35) | ||
3 | .3 | Certificate of Designation of 4.0% Convertible Perpetual Preferred Stock, as filed with the Secretary of State of the State of Delaware on December 20, 2004.(7) | ||
3 | .4 | Certificate of Designations of 3.625% Convertible Perpetual Preferred Stock, as filed with the Secretary of State of the State of Delaware on August 11, 2005.(17) | ||
3 | .5 | Certificate of Designations of 5.75% Mandatory Convertible Preferred Stock, as filed with the Secretary of State of the State of Delaware on January 27, 2006.(19) | ||
3 | .6 | Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of NRG Common Stock Finance I LLC, as filed with the Secretary of State of Delaware on August 14, 2006.(27) | ||
3 | .7 | Certificate of Amendment to Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of NRG Common Stock Finance I LLC, as filed with the Secretary of State of Delaware on February 27, 2008.(36) | ||
3 | .8 | Second Certificate of Amendment to Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of NRG Common Stock Finance I LLC, as filed with the Secretary of State of Delaware on August 8, 2008.(37) | ||
3 | .9 | Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of NRG Common Stock Finance II LLC, as filed with the Secretary of State of Delaware on August 14, 2006.(27) | ||
4 | .1 | Supplemental Indenture dated as of December 30, 2005, among NRG Energy, Inc., the subsidiary guarantors named on Schedule A thereto and Law Debenture Trust Company of New York, as trustee.(13) | ||
4 | .2 | Amended and Restated Common Agreement among XL Capital Assurance Inc., Goldman Sachs Mitsui Marine Derivative Products, L.P., Law Debenture Trust Company of New York, as Trustee, The Bank of New York, as Collateral Agent, NRG Peaker Finance Company LLC and each Project Company Party thereto dated as of January 6, 2004, together with Annex A to the Common Agreement.(2) | ||
4 | .3 | Amended and Restated Security Deposit Agreement among NRG Peaker Finance Company, LLC and each Project Company party thereto, and the Bank of New York, as Collateral Agent and Depositary Agent, dated as of January 6, 2004.(2) | ||
4 | .4 | NRG Parent Agreement by NRG Energy, Inc. in favor of the Bank of New York, as Collateral Agent, dated as of January 6, 2004.(2) | ||
4 | .5 | Indenture dated June 18, 2002, between NRG Peaker Finance Company LLC, as Issuer, Bayou Cove Peaking Power LLC, Big Cajun I Peaking Power LLC, NRG Rockford LLC, NRG Rockford II LLC and Sterlington Power LLC, as Guarantors, XL Capital Assurance Inc., as Insurer, and Law Debenture Trust Company, as Successor Trustee to the Bank of New York.(3) | ||
4 | .6 | Registration Rights Agreement, dated December 21, 2004, by and among NRG Energy, Inc., Citigroup Global Markets Inc. and Deutsche Bank Securities Inc.(6) | ||
4 | .7 | Specimen of Certificate representing common stock of NRG Energy, Inc.(26) | ||
4 | .8 | Indenture, dated February 2, 2006, among NRG Energy, Inc. and Law Debenture Trust Company of New York.(19) | ||
4 | .9 | First Supplemental Indenture, dated February 2, 2006, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(20) |
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4 | .10 | Second Supplemental Indenture, dated February 2, 2006, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(20) | ||
4 | .11 | Form of 7.250% Senior Note due 2014.(20) | ||
4 | .12 | Form of 7.375% Senior Note due 2016.(20) | ||
4 | .13 | Third Supplemental Indenture, dated March 14, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(22) | ||
4 | .14 | Fourth Supplemental Indenture, dated March 14, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(22) | ||
4 | .15 | Fifth Supplemental Indenture, dated April 28, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(23) | ||
4 | .16 | Sixth Supplemental Indenture, dated April 28, 2006, among NRG, the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(23) | ||
4 | .17 | Seventh Supplemental Indenture, dated November 13, 2006, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(28) | ||
4 | .18 | Eighth Supplemental Indenture, dated November 13, 2006, among NRG Energy, Inc., the existing guarantors named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(28) | ||
4 | .19 | Ninth Supplemental Indenture, dated November 13, 2006, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2017.(29) | ||
4 | .20 | Tenth Supplemental Indenture, dated July 19, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(33) | ||
4 | .21 | Eleventh Supplemental Indenture, dated July 19, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(33) | ||
4 | .22 | Twelfth Supplemental Indenture, dated July 19, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2017.(33) | ||
4 | .23 | Thirteenth Supplemental Indenture, dated August 28, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.250% Senior Notes due 2014.(34) | ||
4 | .24 | Fourteenth Supplemental Indenture, dated August 28, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2016.(34) | ||
4 | .25 | Fifteenth Supplemental Indenture, dated August 28, 2007, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as Trustee, re: NRG Energy, Inc.’s 7.375% Senior Notes due 2017.(34) | ||
4 | .26 | Form of 7.375% Senior Note due 2017.(29) | ||
10 | .1 | Note Agreement, dated August 20, 1993, between NRG Energy, Inc., Energy Center, Inc. and each of the purchasers named therein.(4) | ||
10 | .2 | Master Shelf and Revolving Credit Agreement, dated August 20, 1993, between NRG Energy, Inc., Energy Center, Inc., The Prudential Insurance Registrants of America and each Prudential Affiliate, which becomes party thereto.(4) | ||
10 | .3* | Form of NRG Energy Inc. Long-Term Incentive Plan Deferred Stock Unit Agreement for Officers and Key Management.(15) |
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10 | .4* | Form of NRG Energy, Inc. Long-Term Incentive Plan Deferred Stock Unit Agreement for Directors.(15) | ||
10 | .5* | Form of NRG Energy, Inc. Long-Term Incentive Plan Non-Qualified Stock Option Agreement.(8) | ||
10 | .6* | Form of NRG Energy, Inc. Long-Term Incentive Plan Restricted Stock Unit Agreement.(8) | ||
10 | .7* | Form of NRG Energy, Inc. Long Term Incentive Plan Performance Unit Agreement.(15) | ||
10 | .8* | Annual Incentive Plan for Designated Corporate Officers.(9) | ||
10 | .9 | Railroad Car Full Service Master Leasing Agreement, dated as of February 18, 2005, between General Electric Railcar Services Corporation and NRG Power Marketing Inc.(15) | ||
10 | .10 | Purchase Agreement (West Coast Power) dated as of December 27, 2005, by and among NRG Energy, Inc., NRG West Coast LLC (Buyer), DPC II Inc. (Seller) and Dynegy, Inc.(14) | ||
10 | .11 | Purchase Agreement (Rocky Road Power), dated as of December 27, 2005, by and among Termo Santander Holding, L.L.C.(Buyer), Dynegy, Inc., NRG Rocky Road LLC (Seller) and NRG Energy, Inc.(14) | ||
10 | .12 | Stock Purchase Agreement, dated as of August 10, 2005, by and between NRG Energy, Inc. and Credit Suisse First Boston Capital LLC.(17) | ||
10 | .13 | Agreement with respect to the Stock Purchase Agreement, dated December 19, 2008, by and between NRG Energy, Inc. and Credit Suisse First Boston Capital LLC.(1) | ||
10 | .14 | Investor Rights Agreement, dated as of February 2, 2006, by and among NRG Energy, Inc. and Certain Stockholders of NRG Energy, Inc. set forth therein.(21) | ||
10 | .15† | Terms and Conditions of Sale, dated as of October 5, 2005, between Texas Genco II LP and Freight Car America, Inc., (including the Proposal Letter and Amendment thereto).(25) | ||
10 | .16* | Amended and Restated Employment Agreement, dated December 4, 2008, between NRG Energy, Inc. and David Crane.(1) | ||
10 | .17* | CFO Compensation Table.(38) | ||
10 | .18 | Limited Liability Company Agreement of NRG Common Stock Finance I LLC.(27) | ||
10 | .19 | Limited Liability Company Agreement of NRG Common Stock Finance II LLC.(27) | ||
10 | .20 | Note Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance I LLC, Credit Suisse International and Credit Suisse Securities (USA) LLC.(27) | ||
10 | .21 | Amendment Agreement, dated February 27, 2008, to the Note Purchase Agreement by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(36) | ||
10 | .22 | Amendment Agreement, dated August 8, 2008, to the Note Purchase Agreement by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(37) | ||
10 | .23 | Amendment Agreement, dated December 19, 2008, to the Note Purchase Agreement by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(1) | ||
10 | .24 | Agreement with respect to Note Purchase Agreement, dated December 19, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(1) | ||
10 | .25 | Note Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance II LLC, Credit Suisse International and Credit Suisse Securities (USA) LLC, as agent.(27) | ||
10 | .26 | Amendment Agreement, dated December 19, 2008, to the Note Purchase Agreement by and among NRG Common Stock Finance II LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(1) | ||
10 | .27 | Agreement with respect to Note Purchase Agreement, dated December 19, 2008, by and among NRG Common Stock Finance II LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(1) | ||
10 | .28 | Preferred Interest Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance I LLC, Credit Suisse Capital LLC and Credit Suisse Securities (USA) LLC, as agent.(27) | ||
10 | .29 | Preferred Interest Amendment Agreement, dated February 27, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(36) | ||
10 | .30 | Preferred Interest Amendment Agreement, dated August 8, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(37) | ||
10 | .31 | Preferred Interest Amendment Agreement, dated December 19, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(1) |
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10 | .32 | Agreement with respect to Preferred Interest Purchase Agreement, dated December 19, 2008, by and among NRG Common Stock Finance I LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(1) | ||
10 | .33 | Preferred Interest Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance II LLC, Credit Suisse Capital LLC and Credit Suisse Securities (USA) LLC, as agent.(27) | ||
10 | .34 | Preferred Interest Amendment Agreement, dated December 19, 2008, by and among NRG Common Stock Finance II LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(1) | ||
10 | .35 | Agreement with respect to Preferred Interest Purchase Agreement, dated December 19, 2008, by and among NRG Common Stock Finance II LLC, Credit Suisse International, and Credit Suisse Securities (USA) LLC.(1) | ||
10 | .36 | Common Interest Purchase Agreement, dated August 4, 2006, between NRG Energy, Inc. and NRG Common Stock Finance I LLC.(27) | ||
10 | .37 | Common Interest Purchase Agreement, dated August 4, 2006, between NRG Energy, Inc. and NRG Common Stock Finance II LLC.(27) | ||
10 | .38 | Second Amended and Restated Credit Agreement, dated June 8, 2007, by and among NRG Energy, Inc., the lenders party thereto, Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC, Citicorp North America Inc. and Credit Suisse.(32) | ||
10 | .39* | Amended and Restated Long-Term Incentive Plan, dated December 8, 2006.(31) | ||
10 | .40* | NRG Energy, Inc. ExecutiveChange-in-Control and General Severance Agreement, dated December 9, 2008.(1) | ||
10 | .41† | Amended and Restated Contribution Agreement (NRG), dated March 25, 2008, by and among Texas Genco Holdings, Inc., NRG South Texas LP and NRG Nuclear Development Company LLC and Certain Subsidiaries Thereof.(36) | ||
10 | .42† | Contribution Agreement (Toshiba), dated February 29, 2008, by and between Toshiba Corporation and NRG Nuclear Development Company LLC.(36) | ||
10 | .43† | Multi-Unit Agreement, dated February 29, 2008, by and among Toshiba Corporation, NRG Nuclear Development Company LLC and NRG Energy, Inc.(36) | ||
10 | .44† | Amended and Restated Operating Agreement of Nuclear Innovation North America LLC, dated May 1, 2008(36) | ||
12 | .1 | NRG Energy, Inc. Computation of Ratio of Earnings to Fixed Charges.(1) | ||
12 | .2 | NRG Energy, Inc. Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividend Requirements.(1) | ||
21 | Subsidiaries of NRG Energy. Inc.(1) | |||
23 | .1 | Consent of KPMG LLP.(1) | ||
31 | .1 | Rule 13a-14(a)/15d-14(a) certification of David W. Crane.(1) | ||
31 | .2 | Rule 13a-14(a)/15d-14(a) certification of Clint C. Freeland.(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. | |
† | Portions of this exhibit have been redacted and are subject to a confidential treatment request filed with the Secretary of the Securities and Exchange Commission pursuant toRule 24b-2 under the Securities Exchange Act of 1934, as amended. | |
(1) | Filed herewith. | |
(2) | Incorporated herein by reference to NRG Energy, Inc.’s annual report onForm 10-K filed on March 16, 2004. | |
(3) | Incorporated herein by reference to NRG Energy, Inc.’s annual report onForm 10-K filed on March 31, 2003. | |
(4) | Incorporated herein by reference to NRG Energy Inc.’s Registration Statement onForm S-1, as amended, Registration No.333-33397. | |
(5) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on November 19, 2003. |
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(6) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 27, 2004. | |
(7) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 27, 2004. | |
(8) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q for the quarter ended September 30, 2004. | |
(9) | Incorporated herein by reference to NRG Energy, Inc.’s 2004 proxy statement on Schedule 14A filed on July 12, 2004. | |
(10) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q for the quarter ended March 31, 2004. | |
(11) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on October 3, 2005. | |
(12) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q for the quarter ended June 30, 2005. | |
(13) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on January 4, 2006. | |
(14) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 28, 2005. | |
(15) | Incorporated herein by reference to NRG Energy, Inc.’s annual report onForm 10-K filed on March 30, 2005. | |
(16) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on May 24, 2005. | |
(17) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on August 11, 2005. | |
(18) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on August 3, 2005. | |
(19) | Incorporated herein by reference to NRG Energy, Inc.’sForm 8-A filed on January 27, 2006. | |
(20) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on February 6, 2006. | |
(21) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on February 8, 2006. | |
(22) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on March 16, 2006. | |
(23) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on May 3, 2006. | |
(24) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on May 4, 2006. | |
(25) | Incorporated herein by reference to NRG Energy, Inc.’s annual report onForm 10-K filed on March 7, 2006. | |
(26) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q filed on August 4, 2006. | |
(27) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on August 10, 2006. | |
(28) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on November 14, 2006. | |
(29) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on November 27, 2006. | |
(30) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 26, 2007. | |
(31) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q filed on May 2, 2007. | |
(32) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on June 13, 2007. | |
(33) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on July 20, 2007. | |
(34) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on September 4, 2007. | |
(35) | Incorporated herein by reference to NRG Energy, Inc.’s annual report onForm 10-K filed on February 28, 2008. | |
(36) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q filed on May 1, 2008. | |
(37) | Incorporated herein by reference to NRG Energy, Inc.’s quarterly report onForm 10-Q filed on October 30, 2008. | |
(38) | Incorporated herein by reference to NRG Energy, Inc.’s current report onForm 8-K filed on December 9, 2008. |
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