UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

 

 

 

Form 10-K

 

 

Commission file No. 001-15891

NRG Energy, Inc.

(Exact name of registrant as specified in its charter)

 

 

(609) 524-4500

(Registrant’s telephone number, including area code:)

 

 

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, par value $0.01 per share

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes  þ      No  o

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes  o      No  þ

 

Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.  Yes  þ      No  o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

(Do not check if a smaller reporting company)

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  o      No  þ

 

As of the last business day of the most recently completed second fiscal quarter, the aggregate market value of the common stock of the registrant held by non-affiliates was approximately $10,001,849,139 based on the closing sale price of $42.90 as reported on the New York Stock Exchange.

 

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.  Yes  þ      No  o

 

Indicate the number of shares outstanding of each of the registrant’s classes of common stock as of the latest practicable date.

 

 

Documents Incorporated by Reference:

 

Portions of the Proxy Statement for the 2009 Annual Meeting of Stockholders

 

 

TABLE OF CONTENTS

 

Glossary of Terms

 

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:

 

 

 

 

 

 

 

PART I

 

Operational Performance —  The Company is focused on increasing value from its existing assets. Through the FOR NRG initiative, NRG will continue to focus on extracting value from its portfolio by improving plant performance, reducing costs and harnessing the Company’s advantages of scale in the procurement of fuels and other commodities, parts and services, and in doing so improving the Company’s return on invested capital, or ROIC. FOR NRG is a companywide effort designed to increase ROIC through operational performance improvements to the Company’s asset fleet, along with a range of initiatives at plants and at corporate offices to reduce costs, or in some cases, monetize or reduce excess working capital and other assets. The FOR NRG accomplishments include both recurring and one-time improvements measured from a prior base year. For plant operations, the program measures cumulative current year benefits using current gross margins multiplied by the change in baseline levels of certain key performance indicators. The plant performance benefits include both positive and negative results for plant reliability, capacity, heat rate and station service.

 

In addition to the FOR NRG initiative, the Company seeks to maximize profitability and manage cash flow volatility through the Company’s commercial operations strategy. The Company will continue to execute asset-based risk management, hedging, marketing and trading strategies within well-defined risk and liquidity guidelines in order to manage the value of the Company’s physical and contractual assets. The Company’s marketing and hedging philosophy is centered on generating stable returns from its portfolio of baseload power generation assets while preserving an ability to capitalize on strong spot market conditions and to capture the extrinsic value of the Company’s intermediate and peaking facilities and portions of its baseload fleet. NRG believes that it can successfully execute this strategy by leveraging its (i) expertise in marketing power and ancillary services, (ii) its knowledge of markets, (iii) its balanced financial structure and (iv) its diverse portfolio of power generation assets.

 

Finally, NRG remains focused on cash flow and maintaining appropriate levels of liquidity, debt and equity in order to ensure continued access to capital for investment, to enhance risk-adjusted returns and to provide flexibility in executing NRG’s business strategy during business downturns, including a regular return of capital to its shareholders. NRG will continue to focus on maintaining operational and financial controls designed to ensure that the Company’s financial position remains strong.

 

Development —  NRG is favorably positioned to pursue growth opportunities through expansion of its existing generating capacity and development of new generating capacity at its existing facilities. NRG intends to invest in its existing assets through plant improvements, repowerings, brownfield development and site expansions to meet anticipated requirements for additional capacity in NRG’s core markets. Through the Repowering NRG initiative, NRG will continue to develop, construct and operate new and enhanced power generation facilities at its existing sites, with an emphasis on new baseload capacity that is supported by long-term power sales agreements and financed with limited or non-recourse project financing. Repowering NRG is a comprehensive portfolio redevelopment program designed to develop, construct and operate new multi-fuel, multi-technology, highly efficient and environmentally responsible generation capacity over the next decade. Through this initiative, the Company anticipates retiring certain existing units and adding new generation to meet growing demand in the Company’s core markets, with an emphasis on new capacity that is expected to be supported by long-term hedging programs, including Power Purchase Agreements, or PPAs, and financed with limited or non-recourse project financing. NRG expects that these efforts will provide one or more of the following benefits: improved heat rates; lower delivered costs; expanded electricity production capability; an improved ability to dispatch economically across the regional general portfolio; increased technological and fuel diversity; and reduced environmental impacts, including facilities that either have near zero greenhouse gas, or GHG, emissions or can be equipped to capture and sequester GHG emissions.

 

New Businesses and New Technology  —  NRG is focused on the development and investment in energy-related new businesses and new technologies where the benefits of such investments represent significant commercial opportunities and create a comparative advantage for the Company, including low or no GHG emitting energy generating sources, such as nuclear, wind, solar thermal, photovoltaic, “clean’’ coal and gas, and the employment of post-combustion carbon capture technologies. In 2008, the Company began to increase its focus on ways to invest in or support the development of new energy-related businesses and technologies that could advance its multi-fuel, multi-technology growth strategy and look for new ways to reduce carbon emissions from its overall fleet, and we expect to continue to do so in the future. Furthermore, the Company intends to capitalize on the high growth opportunities presented by government-mandated renewable portfolio standards, tax incentives and loan

guaranties for renewable energy projects and new technologies and expected future carbon regulation. A primary focus of this strategy is supported by the econrg initiative whereby NRG is pursuing investments in new generating facilities and technologies that will be highly efficient and will employ no and low carbon technologies to limit CO ₂ emissions and other air emissions. econrg represents NRG’s commitment to environmentally responsible power generation by addressing the challenges of climate change, clean air and water, and conservation of our natural resources while taking advantage of business opportunities that may inure to NRG as a result of our demonstration and deployment of “green” technologies. Within NRG, econrg builds upon a foundation in environmental compliance and embraces environmental initiatives for the benefit of our communities, employees and shareholders, such as encouraging investment in new environmental technologies, pursuing activities that preserve and protect the environment and encouraging changes in the daily lives of the Company’s employees.

 

Company-Wide Initiatives —  In addition, the Company’s overall strategy is also supported by Future NRG and NRG Global Giving initiatives. Future NRG is the Company’s workforce planning and development initiative and represents NRG’s strong commitment to planning for future staffing requirements to meet the on-going needs of the Company’s current operations in addition to the Company’s Repowering NRG initiatives. Future NRG encompasses analyzing the demographics, skill set and size of the Company’s workforce in addition to the organizational structure with a focus on succession planning, training, development, staffing and recruiting needs. Included under the Future NRG umbrella is NRG University, which provides leadership, managerial, supervisory and technical training programs and individual skill development courses. NRG Global Giving is designed to enhance respect for the community, which is one of NRG’s core values. Our Global Giving Program invests NRG’s resources to strengthen the communities where we do business and seeks to make community investments in four focus areas: community and economic development, education, environment and human welfare.

 

Finally, NRG will continue to pursue selective acquisitions, joint ventures and divestitures to enhance its asset mix and competitive position in the Company’s core markets. NRG intends to concentrate on opportunities that present attractive risk-adjusted returns. NRG will also opportunistically pursue other strategic transactions, including mergers, acquisitions or divestitures.

 

Competition and Competitive Strengths

 

Competition — Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. NRG competes on the basis of the location of its plants and ownership of multiple plants in various regions, which increases the stability and reliability of its energy supply. Wholesale power generation is basically a local business that is currently highly fragmented relative to other commodity industries and diverse in terms of industry structure. As such, there is a wide variation in terms of the capabilities, resources, nature and identity of the companies NRG competes with depending on the market.

 

Scale and diversity of assets — NRG has one of the largest and most diversified power generation portfolios in the US, with approximately 22,925 MW of fossil fuel and nuclear generation capacity in 177 active generating units at 43 plants and ownership interests in two wind farms representing 195 MW of wind generation capacity, as of December 31, 2008. The Company’s power generation assets are diversified by fuel-type, dispatch level and region, which help mitigate the risks associated with fuel price volatility and market demand cycles. NRG’s US baseload facilities, which consist of approximately 8,715 MW of generation capacity measured as of December 31, 2008, provide the Company with a significant source of stable cash flow, while its intermediate and peaking facilities, with approximately 14,210 MW of generation capacity as of December 31, 2008, provide NRG with opportunities to capture the significant upside potential that can arise from time to time during periods of high demand. In addition, approximately 15% of the Company’s domestic generation facilities have dual or multiple fuel capability, which allows most of these plants to dispatch with the lowest cost fuel option. In 2008, NRG completed the construction of the Sherbino (150 MW including partner’s interests of 75 MW) and Elbow Creek (120 MW) wind farms which provide electricity to the Company’s core region.

The following chart demonstrates the diversification of NRG’s domestic power generation assets as of December 31, 2008:

 

 

Reliability of future cash flows  — NRG has hedged a significant portion of its expected baseload generation capacity with decreasing hedged levels through 2014. NRG also has cooperative load contract obligations in South Central region which expire over various dates through 2026. The Company has the capacity and intent to enter into additional hedges when market conditions are favorable. In addition, as of December 31, 2008, the Company had purchased fuel forward under fixed price contracts, with contractually-specified price escalators, for approximately 51% of its expected baseload coal generation output from 2009 to 2014. The hedge percentage is reflective of the current agreement of the Jewett mine in which NRG has the contractual ability to adjust volumes in future years. These forward positions provide a stable and reliable source of future cash flow for NRG’s investors, while preserving a portion of its generation portfolio for opportunistic sales to take advantage of market dynamics.

 

Favorable cost dynamics for baseload power plants — In 2008, approximately 91% of the Company’s domestic generation output was from plants fueled by coal or nuclear fuel. In many of the competitive markets where NRG operates, the price of power is typically set by the marginal costs of natural gas-fired and oil-fired power plants that currently have substantially higher variable costs than solid fuel baseload power plants. As a result of NRG’s lower marginal cost for baseload coal and nuclear generation assets, the Company expects the baseload assets in the Electric Reliability Council of Texas, or ERCOT, to generate power majority of the time they are available.

 

Locational advantages — Many of NRG’s generation assets are located within densely populated areas that are characterized by significant constraints on the transmission of power from generators outside the particular region. Consequently, these assets are able to benefit from the higher prices that prevail for energy in these markets during periods of transmission constraints. NRG has generation assets located within New York City, southwestern Connecticut, Houston and the Los Angeles and San Diego load basins; all areas, which experience from time-to-time and to varying degrees of constraints on the transmission of electricity. This gives the Company the opportunity to capture additional revenues by offering capacity to retail electric providers and others, selling power at prevailing market prices during periods of peak demand and providing ancillary services in support of system reliability. Also, these facilities are often ideally situated for repowering or the addition of new capacity, because their location and existing infrastructure give them significant advantages over developed sites in their regions that do not have process infrastructure.

 

In understanding NRG’s business, the Company believes that certain performance metrics are particularly important. These are industry statistics defined by the North American Electric Reliability Council, or NERC, and are more fully described below:

 

Annual Equivalent Availability Factor, or EAF — Measures the percentage of maximum generation available over time as the fraction of net maximum generation that could be provided over a defined period of time after all types of outages and deratings, including seasonal deratings, are taken into account.

 

Gross heat rate — The gross heat rate for the Company’s fossil-fired power plants represents the average amount of fuel in a BTU required to generate one kWh of electricity divided by the generator output.

 

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.

The tables below present the North American power generation performance metrics for the Company’s power plants discussed above for the years ended December 31, 2008 and 2007:

 

 

 

 

Employees

 

As of December 31, 2008, NRG had 3,526 employees, approximately 1,663 of whom were covered by US bargaining agreements. During 2008, the Company did not experience any labor stoppages or labor disputes at any of its facilities.

Generation Asset Overview

 

NRG has a significant power generation presence in major competitive power markets of the US as set forth in the map below:

 

 

 

 

As of December 31, 2008, the Company’s power generation assets consisted of approximately 10,495 MW of gas-fired; 7,540 MW of coal-fired; 3,715 MW of oil-fired; 1,175 MW of nuclear; and 195 MW of wind generating capacity in the US. In addition, NRG also owns approximately 115 MW of thermal capacity domestically as well as 1,080 MW of power generation capacity overseas. The Company’s US power generation portfolio by dispatch level is comprised of approximately 38% baseload, 36% intermediate, 25% peaking and 1% intermittent units.

 

The following is a discussion of NRG’s generation assets by segment for the year ended December 31, 2008.

 

Texas Region  — As of December 31, 2008, NRG’s generation assets in the Texas region consisted of approximately 5,340 MW of baseload generation assets, approximately 195 MW of intermittent wind generation assets, excluding partner interests of 75 MW, in addition to approximately 5,475 MW of intermediate and peaking natural gas-fired assets. NRG realizes a substantial portion of its revenue and cash flow from the sale of power from the Company’s three baseload power plants located in the ERCOT market that use solid fuel: W.A. Parish which uses coal, Limestone which use lignite and coal, and an undivided 44% interest in two nuclear generating units at South Texas Project, or STP. In 2008, NRG announced the completion of the construction of two wind farms, Sherbino Wind Farm and Elbow Creek Wind Farm, which are also located in the ERCOT market. Power plants are generally dispatched in order of lowest operating cost and as of May 2008 approximately 64% of the net generation capacity in the ERCOT market was natural gas-fired. In the current natural gas price environment, NRG’s three solid fuel baseload facilities and two wind farms have significantly lower operating costs than gas plants. NRG expects these three solid-fuel facilities to operate the majority of the time when available, subject to planned and forced outages.

Northeast Region  — As of December 31, 2008, NRG generation assets in the Northeast region of the US consisted of approximately 7,020 MW generation capacity from the Company’s power plants within the control areas of the New York Independent System Operator, or NYISO, the Independent System Operator — New England, or ISO-NE, and the PJM Interconnection LLC, or PJM. Certain of these assets are located in transmission constrained areas, including approximately 1,415 MW of in-city New York City generation capacity and approximately 575 MW of southwest Connecticut generation capacity. As of December 31, 2008, NRG’s generation assets in the Northeast region consisted of approximately 1,870 MW of baseload generation assets and approximately 5,150 MW of intermediate and peaking assets.

 

South Central Region  — As of December 31, 2008, NRG generation assets in the South Central region of the US consisted of approximately 2,845 MW of generation capacity, making NRG the third largest generator in the Southeastern Electric Reliability Council/Entergy, or SERC-Entergy, region. The Company’s generation assets in Louisiana consist of its primary asset, Big Cajun II, a coal-fired plant located near Baton Rouge, Louisiana which has approximately 1,490 MW of baseload capacity and 905 MW of intermediate and peaking assets. A significant portion of the region’s generation capacity has been sold to eleven cooperatives within the region through 2026. From time to time, the Company may contract for intermediate generation capacity to support its load obligations. In addition, the region also operates 450 MW of peaking generation in Rockford, Illinois under the PJM region.

 

West Region  — As of December 31, 2008, NRG generation assets in the West region of the US consisted of approximately 2,130 MW of generation capacity, primarily located in the California Independent System Operator, or CAISO, control area. The Company’s generation assets in the West region are predominately intermediate and peaking duty natural gas-fired plants located in southern California. In addition, the region owns 50% interest in a 90 MW baseload, gas-fired plant located in Nevada.

 

International Region  — As of December 31, 2008, NRG had net ownership in approximately 1,080 MW of power generating capacity in Australia and Germany. In addition to traditional power generation facilities, NRG also owns equity interests in certain coal mines in Germany.

 

Thermal  — NRG owns thermal and chilled water businesses that generate approximately 1,020 MW thermal equivalents. In addition, NRG’s thermal segment owns certain power plants with approximately 115 MW of power generating capacity located in Delaware and Pennsylvania.

 

Commercial Operations Overview

 

NRG seeks to maximize profitability and manage cash flow volatility through the marketing, trading and sale of energy, capacity and ancillary services into spot, intermediate and long-term markets and through the active management and trading of emissions allowances, fuel supplies and transportation-related services. The Company’s principal objectives are the realization of the full market value of its asset base, including the capture of its extrinsic value, the management and mitigation of commodity market risk and the reduction of cash flow volatility over time.

 

NRG enters into power sales and hedging arrangements via a wide range of products and contracts, including power purchase agreements, fuel supply contracts, capacity auctions, natural gas swap agreements and other financial instruments. The PPAs that NRG enters into require the Company to deliver MWh of power to its counterparties. In addition, because changes in power prices in the markets where NRG operates are generally correlated to changes in natural gas prices, NRG uses hedging strategies which may include power and natural gas forward sales contracts to manage the commodity price risk primarily associated with the Company’s base load generation assets. The objective of these hedging strategies is to stabilize the cash flow generated by NRG’s portfolio of assets.

The following table summarizes NRG’s US baseload capacity and the corresponding revenues and average natural gas prices resulting from baseload hedge agreements extending beyond December 31, 2008 and through 2014:

 

 

 

 

Fuel Supply and Transportation

 

NRG’s fuel requirements consist primarily of nuclear fuel and various forms of fossil fuel including oil, natural gas and coal, including lignite. The prices of oil, natural gas and coal are subject to macro- and micro-economic forces that can change dramatically in both the short- and long-term. The Company obtains its oil, natural gas and coal from multiple suppliers and transportation sources. Although availability is generally not an issue, localized shortages, transportation availability and supplier financial stability issues can and do occur. The preceding factors related to the sources and availability of raw materials are fairly uniform across the Company’s business segments.

 

Coal — The Company is largely hedged for its domestic coal consumption over the next few years. Coal hedging is dynamic and is based on forecasted generation and market volatility. As of December 31, 2008, NRG had purchased forward contracts to provide fuel for approximately 51% of the Company’s requirements from 2009 through 2014. NRG arranges for the purchase, transportation and delivery of coal for the Company’s baseload coal plants via a variety of coal purchase agreements, rail/barge transportation agreements and rail car lease arrangements. The Company purchased approximately 35 million tons of coal in 2008, of which 94% is Power River Basin coal and lignite. The Company is one of the largest coal purchasers in the US.

The following table shows the percentage of the Company’s coal and lignite requirements from 2009 through 2014 that have been purchased forward:

 

 

 

 

As of December 31, 2008, NRG had approximately 6,349 privately leased or owned rail cars in the Company’s transportation fleet. NRG has entered into rail transportation agreements with varying tenures that provide for substantially all of the Company’s rail transportation requirements up to the next ten years.

 

Natural Gas — NRG operates a fleet of natural gas plants in the Texas, Northeast, South Central and West regions which are primarily comprised of peaking assets that run in times of high power demand. Due to the uncertainty of their dispatch, the fuel needs are managed on a spot basis as it is not prudent to forward purchase fixed price natural gas for units that may not run. The Company contracts for natural gas storage services as well as natural gas transportation services to ensure delivery of natural gas when needed.

 

Nuclear Fuel — STP’s owners satisfy STP’s fuel supply requirements by (i) acquiring uranium concentrates and contracting for conversion of the uranium concentrates into uranium hexafluoride, (ii) contracting for enrichment of uranium hexafluoride, and (iii) contracting for fabrication of nuclear fuel assemblies. NRG is party to a number of long-term forward purchase contracts with many of the world’s largest suppliers covering STP requirements for uranium and conversion services for the next five years, and with substantial portions of STP’s requirements procured thereafter. NRG is party to long-term contracts to procure STP’s requirements for enrichment services and fuel fabrication for the life of the operating license.

 

Seasonality and Price Volatility

 

Annual and quarterly operating results can be significantly affected by weather and energy commodity price volatility. Significant other events, such as the demand for natural gas, interruptions in fuel supply infrastructure and relative levels of hydroelectric capacity can increase seasonal fuel and power price volatility. NRG derives a majority of its annual revenues in the months of May through October, when demand for electricity is at its highest in the Company’s core domestic markets. Further, power price volatility is generally higher in the summer months, traditionally NRG’s most important season. The Company’s second most important season is the winter months of December through March when volatility and price spikes in underlying delivered fuel prices have tended to drive seasonal electricity prices. The preceding factors related to seasonality and price volatility are fairly uniform across the Company’s business segments.

 

Operations Overview

 

NRG provides support services to the Company’s generation facilities to ensure that high-level performance goals are developed, best practices are shared and resources are appropriately balanced and allocated to maximize results for the Company. NRG sets performance goals for equivalent forced outage rates, or EFOR, availability, procurement costs, operating costs, safety and environmental compliance.

 

Support services include safety, security, and systems. These services also include operations planning and the development and dissemination of consistent policies and practices relating to plant operations.

To support Repowering NRG environmental capital expenditures and all major capital expenditure projects initiatives, the Company organized its project execution process into one centralized group consisting of Engineering, Procurement and Construction, or EPC. This group combines regional engineering functions with development project engineering, project management, procurement and construction functions to provide a consistent approach to the major capital projects. This has enabled NRG to leverage both the procurement of major equipment as well as outside engineering resources through standardized work processes and work packaging. This process has led to identifying commonality in major equipment that can be procured from Original Equipment Manufacturers, or OEMs, as well as design processes. As a result, NRG achieves cost savings by minimizing the number of outside engineering and construction resources, which provide detailed design and construction services required to complete projects, in addition to and by ensuring a consistent engineering and construction approach across all projects.

 

FOR NRG Update

 

In 2007, the Company announced the acceleration and planned conclusion of the FOR NRG 1.0 program by bringing forward the previously announced 2009 target of $250 million to 2008. Improvements in reliability throughout the baseload fleet were the drivers of the year-to-date program performance. In 2008, the Company achieved $259 million of implemented FOR NRG 1.0 improvements which exceeded the established $250 million goal. The FOR NRG 1.0 program was measured from a 2004 baseline, with the exception of the Texas region where benefits were measured using 2005 as the base year.

 

Beginning in January 2009, the Company transitioned to FOR NRG 2.0 to target an incremental 100 basis point improvement to the Company’s ROIC by 2012. The initial targets for FOR NRG 2.0 were based upon improvements in the Company’s ROIC as measured by increased cash flow. The economic goals of FOR NRG 2.0 will focus on: (i) revenue enhancement, (ii) cost savings, and (iii) asset optimization, including reducing excess working capital and other assets. The FOR NRG 2.0 program will measure its progress towards the FOR NRG 2.0 goals by using the Company’s 2008 financial results as a baseline, while plant performance calculations will be based upon the average full-year plant key performance indicators for years the 2006-2008.

 

Environmental Capital Expenditures

 

Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures to be incurred from 2009 through 2013 to meet NRG’s environmental commitments will be approximately $1.2 billion. These capital expenditures, in general, are related to installation of particulate, SO ₂ , NO _x , and mercury controls to comply with federal and state air quality rules and consent orders, as well as installation of “Best Technology Available” under the Phase II 316(b) rule. NRG continues to explore cost effective alternatives that can achieve desired results. While this estimate reflects schedules and controls to meet anticipated reduction requirements, the full impact on the scope and timing of environmental retrofits cannot be determined until issuance of final rules by the United States Environmental Protection Agency, or USEPA.

 

The following table summarizes the estimated environmental capital expenditures for the referenced periods by region:

 

 

NRG’s current contracts with the Company’s rural electrical customers in the South Central region allow for recovery of a significant portion of the capital costs, along with a capital return incurred by complying with new laws, including interest over the asset life of the required expenditures. Actual recoveries will depend, among other things, on the duration of the contracts.

Carbon Update

 

There is a marked shift towards federal action to address climate change under the Obama administration, which has made clear its intention to make climate change policy a priority for the US through legislation, regulation, and global leadership. President Obama reiterated this commitment in his inaugural address. Congressman Waxman, who sees aggressive action on climate change as a major priority, was elected chair of the House Energy and Commerce Committee and announced that a climate change bill would be delivered out of committee before Memorial Day.

 

The fossil-fuel based electric generators contribute to GHG emissions. In 2008, in the course of producing approximately 80 million MWh of electricity, NRG’s power plants emitted approximately 68 million tonnes of CO ₂ , of which approximately 61 million tonnes were emitted in the US, approximately 4 million tonnes in Germany, and approximately 3 million tonnes in Australia.

 

The Company has a multifold strategy with respect to climate change and related GHG regulation. First, the Company is seeking to shape public policy as it emerges at various levels of government in order to ensure that such legislation is fair and effective in reducing GHG emissions. To ensure such effectiveness, NRG believes it is particularly important that legislation effectively support the development, demonstration and deployment of low and no CO ₂ power generation technologies, and that it sets out a transitional allocation approach that buffers initial net compliance costs while transitioning to a full auction. The Company is carrying out its efforts to influence public policy on its own and as part of various collective efforts. For example in January 2009, NRG joined with other members of the United States Climate Action Partnership, or USCAP, to issue the “Blueprint for Legislative Action,” a detailed framework for legislation to slow, stop and reverse the growth of GHG emissions to achieve an 80% reduction from 2005 levels by 2050.

 

Second, the Company is actively pursuing investments in new generating facilities and technologies that will be highly efficient and will employ technologies to minimize CO ₂ emissions and other air emissions through its Repowering NRG program. The Company anticipates that these investments will result in significant long-term GHG intensity reductions in its generating portfolio. The most notable of these projects in terms of the potential impact on the GHG intensity of the Company’s portfolio is the 2,700 MW STP units 3 and 4 nuclear project in Texas. NRG has formed Nuclear Innovation North America, or NINA, a joint venture with the Toshiba American Nuclear Energy Corporation, to facilitate the development of STP 3 and 4 as well as additional nuclear projects. Further, in 2008, NRG’s subsidiary, Padoma Wind Power, LLC, or Padoma, brought 270 MW of wind generating capacity on-line in west Texas at two facilities: (i) the 150 MW Sherbino I Wind Farm LLC, or Sherbino, a 50/50 joint venture with a subsidiary of BP Alternative Energy North America Inc., or BP, and (ii) the wholly-owned, 120 MW Elbow Creek Wind Power LLC facility. The Company is actively developing low and no GHG emitting wind, solar, biomass and natural gas projects. The extent to which these projects, and the remaining coal projects under development, impact the Company’s overall climate change exposure will depend on the Company’s ability to complete development of these projects, the nature and geographic reach of any GHG regulation which goes into effect and the extent to which the climate change risk associated with our development projects is allocated between the Company and any offtakers under power purchase agreements or similar arrangements.

 

Third, the Company is seeking to demonstrate through its econrg program the large scale viability of post-combustion CO ₂ capture technologies. NRG is exploring a variety of technologies, including one or more scaled up demonstrations at a Company facility in Texas. The captured CO ₂ would be sequestered through use for enhanced oil recovery or otherwise in suitable geological formations.

 

Fourth, the Company is preparing for the commercial operations activities which will be required as part of any climate change regulatory scheme that is implemented, including managing a portfolio of GHG offsets and CO ₂ allowances. For example, the Company is a member of the Chicago Climate Exchange, a CO ₂ emissions reduction, registry and trading system, and has been active in both RGGI auctions to date.

 

Fifth, and finally, the Company has for the past year, and will going forward, factor into its capital investment decision making process assumptions regarding the costs of complying with anticipated climate change regulations. As a result, all decisions with respect to acquisitions, repowerings, project development and further investment in

our existing facilities will be made on the assumption that there will be a cost associated with GHG emissions in the future.

 

Nuclear Innovation North America

 

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 City of San Antonio’s agent City Public Service Board of San Antonio, or CPS Energy, at the STP nuclear power station site. NRG’s rights to develop STP units 3 and 4 have been contributed to special purpose subsidiaries of NINA. NINA will focus only on the development of new projects and will not be involved in the operations of the existing STP units 1 and 2.

 

Toshiba American Nuclear Energy Corporation, or TANE, a wholly owned subsidiary of Toshiba Corporation, will serve as the prime contractor on NINA’s projects and is a minority shareholder with NRG in the NINA venture. TANE is currently prime contractor of the STP units 3 and 4 project and is providing licensing support and leading all engineering and scheduling activities, which ultimately will lead to responsibility for constructing the project. TANE received a 12% equity ownership in NINA in exchange for $300 million invested in NINA in six annual installments of $50 million, the first of which was received in 2008 and the last three of which are subject to certain conditions. Half of this investment will be to fund development activities related to STP units 3 and 4. The other half will be targeted towards developing and deploying additional Advanced Boiling Water Reactor, or ABWR, projects in North America with other potential partners. TANE is also extending pre-negotiated EPC terms to NINA for two additional two-unit nuclear projects similar to the terms being offered for the STP unit 3 and 4 development.

 

NINA intends to use the Nuclear Regulatory Commission, or NRC, certified ABWR design, with only a limited number of changes to enhance safety and construction schedules. On November 30, 2007, the NRC accepted the Company’s Combined Construction and Operating License Application, or COLA, which was filed September 24, 2007, together with San Antonio’s CPS Energy and South Texas Project Nuclear Operating Company, or STPNOC, to build and operate two new nuclear units at the STP nuclear power station site. On September 30, 2008, NINA filed a revision to the COLA to list Toshiba as the primary vendor. NINA received the combined license review schedule from the NRC on February 11, 2009. Issuing the schedule marks the continuation of NRC’s review of the STP expansion application as amended on September 2008. The Company expects to achieve commercial operation for Unit 3 in 2015 and commercial operation for Unit 4 approximately 12 months thereafter. The total rated capacity of the new units, STP units 3 and 4, is expected to equal or exceed 2,700 MW.

 

In October 2007, NRG and the City of San Antonio, acting through CPS Energy, entered into an interim agreement whereby the parties agreed to be equal partners in the development of the two new units, and, in the event either party chooses at any time not to proceed, gives the other party the right to proceed with the project on its own.

 

Repowering NRG Update

 

NRG has a comprehensive portfolio redevelopment program, referred to as Repowering NRG, which involves the development, construction and operation of new multi-fuel, multi-technology generation capacity at NRG’s existing domestic sites to meet the growing demand in the Company’s core markets. Through this initiative, the Company anticipates retiring certain existing units and adding new generation, with an emphasis on new baseload capacity that is expected to be supported by long-term PPAs and financed with limited or non-recourse project financing. NRG continues to expect that these repowering investments will provide one or more of the following benefits: improved heat rates; lower delivered costs; expanded electricity production capability; an improved ability to dispatch economically across the Merit Order; increased technological and fuel diversity; and reduced environmental impacts. The Company anticipates that the Repowering NRG program will also result in indirect benefits, including the continuation of operations and retention of key personnel at its existing facilities.

 

A critical aspect of the Repowering NRG program is the extent to which the Company is actively pursuing investments in new generating facilities that will be highly efficient and will employ no and/or low carbon technologies to limit CO ₂ emissions and other air emissions. The Company anticipates that these investments will result in long-term GHG intensity reductions in its generating portfolio.

The Company expects that the overall capital expenditures in connection with the program will be substantial. The Company plans to mitigate the capital cost of the program through equity partnerships and public-private partnerships, as well as through the reimbursement of development fees for certain projects. To further mitigate the investment risks, NRG anticipates entering into long-term PPAs and EPC contracts. In addition, the proposed increase in generation capacity and capital costs resulting from Repowering NRG could change as proposed projects are included or removed from the program due to a number of factors, including successfully obtaining required permits, long-term PPAs, availability of financing on favorable terms, and achieving targeted project returns. The projects that have been identified as part of the Repowering NRG program are also subject to change as NRG refines the program to take into account the success rate for completion of projects, changes in the targeted minimum return thresholds, and evolving market dynamics.

 

Currently, NRG has various projects in certain stages of development that includes a new biomass project at Montville Generating Station and the repowering of Big Cajun I and El Segundo sites. As a result of permitting delays related to the on-going Natural Resource Defense Council claims, the El Segundo project is unlikely to reach its original completion date of June 1, 2011.

 

The following is a summary of repowering projects that have either been completed or are under construction. In addition, NRG continues to participate in active bids in response to requests for proposals in markets in which it operates, particularly in the West and Northeast regions.

 

Plants Completed and Operating

 

Cos Cob  — On June 26, 2008, NRG announced the completion of the repowering of its Cos Cob generating station in Fairfield County, Connecticut which added 40 MW of power to the site. The Company funded and developed this project which added two new gas turbine units, between the existing three units, bringing total site output to 100 MW. All five units were retrofitted to use water injection technology for NOx, resulting in a 50% net station reduction in NO _x . The site also converted to burn ultra-low sulfur distillated oil resulting in a 97% reduction in SO ₂ emissions.

 

Sherbino Wind Farm — On October 22, 2008, NRG and its 50/50 joint venture partner, BP, announced the completion of its Sherbino project in Pecos County, Texas. The wind farm was developed by NRG’s subsidiary Padoma together with BP. Padoma managed the construction, which began in late 2007. BP will operate and dispatch the facility. Sherbino is a 150 MW wind farm consisting of 50 Vestas wind turbine generators, each capable of generating up to 3 MW of power. 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.

 

Plants under Construction

 

Cedar Bayou Generating Station — In August 2007, NRG Cedar Bayou Development Company LLC, or NRG Cedar Bayou, a subsidiary of NRG Energy, Inc., and EnergyCo Cedar Bayou 4, LLC, or EnergyCo Cedar Bayou, a subsidiary of Optim Energy, LLC, formally EnergyCo, LLC, which is a joint venture between PNM Resources Inc. and a subsidiary of Cascade Investment, LLC, agreed to jointly develop, construct, operate and own, on a 50/50 undivided interest basis, a new 550 MW combined cycle natural gas turbine generating plant at NRG’s Cedar Bayou Generating Station in Chambers County, Texas. On July 26, 2007, the Texas Commission on Environmental Air Quality, or TCEQ, granted an air permit required for construction and operation of the new plant, and on August 1, 2007, NRG Cedar Bayou and EnergyCo Cedar Bayou entered into an EPC agreement with Zachry Construction Corporation. NRG provides construction management services and will also provide various ongoing services related to plant operations and maintenance, and use of existing NRG facilities in return for a fixed fee plus reimbursement of the Company’s costs. NRG will also provide plant operations and maintenance services and access to certain existing infrastructure at the site on a cost reimbursement basis plus a fixed fee. The construction of the project is on schedule and the plant is expected to begin commercial operations in mid-2009.

GenConn Energy LLC — In a procurement process conducted by the Department of Public Utility Control, or DPUC, and finalized in 2008, GenConn Energy LLC, or GenConn, a 50/50 joint venture of NRG and The United Illuminating Company, secured contracts in 2008 with Connecticut Light & Power, or CL&P, for the construction and operation of two 200 MW peaking facilities, at NRG’s Devon and Middletown sites in Connecticut. The contracts, which are structured as contracts for differences for the full output of the new power plants, have a 30-year term and call for commercial operation of the Devon project by June 1, 2010 and the Middletown project by June 1, 2011. GenConn has secured all state permits required for the projects and has entered into contracts for engineering and for the procurement of the 8 GE LM6000 combustion turbines required for the projects. GenConn expects to close on financing for the projects in the first half of 2009.

 

  Regional Business Descriptions

 

NRG is organized into business units, with each of the Company’s core regions operating as a separate business segment as discussed below.

 

TEXAS

 

NRG’s largest business segment is located in Texas and is comprised of investments in generation facilities located in the physical control areas of the ERCOT market. These assets were acquired on February 2, 2006, as part of the acquisition of Texas Genco LLC, or Texas Genco.

 

Operating Strategy

 

The Company’s business in Texas is comprised of four sets of assets: a nuclear plant, solid-fuel baseload plants, gas-fired plants located in and around Houston, and wind farms. NRG’s operating strategy to maximize value and opportunity across these assets is to (i) ensure the availability of the baseload plants to fulfill their commercial obligations under long-term forward sales contracts already in place, (ii) manage the natural gas assets for profitability while ensuring the reliability and flexibility of power supply to the Houston market, (iii) take advantage of the skill sets and market or regulatory knowledge to grow the business through incremental capacity uprates and repowering development of solid-fuel baseload and gas-fired units, and (iv) play a leading role in the development of the ERCOT market by active membership and participation in market and regulatory issues.

 

NRG’s strategy is to sell forward a majority of its solid-fuel baseload capacity in the ERCOT market under long-term contracts or to enter into hedges by using natural gas as a proxy for power prices. Accordingly, the Company’s primary focus will be to keep these solid-fuel baseload units running efficiently. With respect to gas-fired assets, NRG will continue contracting forward a significant portion of gas-fired capacity one to two years out while holding a portion for back-up in case there is an operational issue with one of the baseload units and to provide upside for expanding heat rates. For the gas-fired capacity sold forward, the Company will offer a range of products specific to customers needs. For the gas-fired capacity that NRG will continue to sell commercially into the market, the Company will focus on making this capacity available to the market whenever it is economical to run.

 

The generation performance by fuel-type for the recent three-year period is as shown below:

 

 

 

 

 

 

 

The following is a description of NRG’s most significant revenue generating plants in the Texas region:

 

W.A. Parish — NRG’s W.A. Parish plant is one of the largest fossil-fired plants in the US based on total MWs of generation capacity. This plant’s power generation units include four coal-fired steam generation units with an aggregate generation capacity of 2,475 MW as of December 31, 2008. Two of these units are 645 MW and 650 MW steam units that were placed in commercial service in December 1977 and December 1978, respectively. The other two units are 570 MW and 610 MW steam units that were placed in commercial service in June 1980 and December 1982, respectively. Each of the four coal-fired units have low-NO _x burners and Selective Catalytic Reductions, or SCRs, installed to reduce NO _x emissions and baghouses to reduce particulates. In addition, W.A. Parish Unit 8 has a scrubber installed to reduce SO ₂ emissions.

 

Limestone  — NRG’s Limestone plant is a lignite and coal-fired plant located approximately 140 miles northwest of Houston. This plant includes two steam generation units with an aggregate generation capacity of 1,690 MW as of December 31, 2008. The first unit is an 830 MW steam unit that was placed in commercial service in December 1985. The second unit is an 860 MW steam unit that was placed in commercial service in December 1986. Limestone burns lignite from an adjacent mine, but also burns low sulfur coal and petroleum coke. This serves to lower average fuel costs by eliminating fuel transportation costs, which can represent up to two-thirds of

delivered fuel costs for plants of this type. Both units have installed low-NO _x burners to reduce NO _x emissions and scrubbers to reduce SO ₂ emissions.

 

NRG owns the mining equipment and facilities and a portion of the lignite reserves located at the adjacent mine. Mining operations are conducted by Texas Westmoreland Coal Co., a single purpose, wholly-owned subsidiary of Westmoreland Coal Company and the owner of a substantial portion of the remaining lignite reserves. The contract, entered into August 1999, ended on December 31, 2007. Effective January 1, 2008, NRG entered into an agreement with Texas Westmoreland Coal Co. to continue to supply lignite from the same surface mine adjacent to the facility for a nominal term of ten years with an option for future year supply purchases. This is a “cost-plus” arrangement under which NRG will pay all of Westmoreland’s agreed upon production costs, capital expenditures, and a per ton mark up. The annual volume demand is determined by NRG. The agreement ensures lignite supply to NRG and confirms NRG’s responsibility for the final reclamation at the mine.

 

South Texas Project Electric Generating Station — STP is one of the newest and largest nuclear-powered generation plants in the US based on total megawatts of generation capacity. This plant is located approximately 90 miles south of downtown Houston, near Bay City, Texas and consists of two generation units each representing approximately 1,335 MW of generation capacity. STP’s two generation units commenced operations in August 1988 and June 1989, respectively. For the year ended December 31, 2008, STP had a zero percent forced outage rate and a 98% net capacity factor.

 

STP is currently owned as a tenancy in common between NRG and two other co-owners. NRG owns a 44%, or approximately 1,175 MW, interest in STP, the City of San Antonio owns a 40% interest and the City of Austin owns the remaining 16% interest. Each co-owner retains its undivided ownership interest in the two nuclear-fueled generation units and the electrical output from those units. Except for certain plant shutdown and decommissioning costs and NRC licensing liabilities, NRG is severally liable, but not jointly liable, for the expenses and liabilities of STP. The four original co-owners of STP organized STPNOC to operate and maintain STP. STPNOC is managed by a board of directors composed of one director appointed by each of the three co-owners, along with the chief executive officer of STPNOC. STPNOC is the NRC-licensed operator of STP. No single owner controls STPNOC and most significant commercial as well as asset investment decisions for the existing units must be approved by two or more owners who collectively control more than 60% of the interests.

 

The two STP generation units operate under licenses granted by the NRC that expire in 2027 and 2028, respectively. These licenses may be extended for additional 20-year terms if the project satisfies NRC requirements. Adequate provisions exist for long-term on-site storage of spent nuclear fuel throughout the remaining life of the existing STP plant licenses.

 

Market Framework

 

The ERCOT market is one of the nation’s largest and historically fastest growing power markets. It represents approximately 85% of the demand for power in Texas and covers the entire state, with the exception of the far west (El Paso), a large part of the Texas Panhandle and two small areas in the eastern part of the state. For the past ten years, peak hourly demand in the ERCOT market grew at a compound annual rate of 2.2%, compared to a compound annual rate of growth of 1.9% in the US for the same period. For 2008, hourly demand ranged from a low of 19,665 MW to a high of 62,190 MW. The ERCOT market has limited interconnections compared to other markets in the US — currently limited to 1,106 MW of generation capacity, and wholesale transactions within the ERCOT market are not subject to regulation by the Federal Energy Regulatory Commission, or FERC. Any wholesale producer of power that qualifies as a power generation company under the Texas electric restructuring law and that accesses the ERCOT electric power grid is allowed to sell power in the ERCOT market at unregulated rates.

 

The ERCOT market has experienced significant construction of new generation plants, with over 36,000 MW of new generation capacity added to the market since 1999. As of December 31, 2008, installed generation capacity of approximately 83,000 MW existed in the ERCOT market, including 5,000 MW of generation that has suspended operations, or been “mothballed”. Natural gas-fired generation represents approximately 53,000 MW, or 64%. Approximately 22,400 MW, or 27%, was lower marginal cost generation capacity such as coal, lignite and nuclear plants. NRG’s coal and nuclear fuel baseload plants represent approximately 5,340 MW net, or 24%, of the total

solid fuel baseload net generation capacity in the ERCOT market. Additionally, NRG commenced commercial operations of the Sherbino Wind Farm and Elbow Creek Wind Farm which represents approximately 195 MW generation capacity for the Company. Both Sherbino and Elbow Creek Wind Farms are located in the physical control areas of the ERCOT market.

 

The ERCOT market has established a target equilibrium reserve margin level of approximately 12.5%. The reserve margin for 2008 was 14% forecast to increase to 16% for 2009 per ERCOT’s latest Capacity Demand and Reserve Report. There are currently plans being considered by the Public Utility Commission of Texas, or PUCT, to build a significant amount of transmission from west Texas and continuing across the state to enable wind generation to reach load. The ultimate impact on the reserve margin and wholesale dynamics from these plans are unknown.

 

In the ERCOT market, buyers and sellers enter into bilateral wholesale capacity, power and ancillary services contracts or may participate in the centralized ancillary services market, including balancing energy, which the ERCOT administers. Published in August 2008, the “2007 State of the Market Report for the ERCOT Wholesale Electricity Markets” from the Independent Market Monitor indicated that natural gas prices were the primary driver of the trends in electricity prices from 2003 to 2007. As a result of NRG’s lower marginal cost for baseload coal and nuclear generation assets, the Company expects these ERCOT assets to generate power nearly 100% of the time they are available.

 

The ERCOT market is currently divided into four regions or congestion zones, namely: North, Houston, South and West, which reflect transmission constraints that are commercially significant and which have limits as to the amount of power that can flow across zones. NRG’s W.A. Parish plant, STP, and all its natural gas-fired plants are located in the Houston zone. NRG’s Limestone plant is located in the North zone while the Sherbino and Elbow Creek wind farms are located in the West Zone.

 

The ERCOT market operates under the reliability standards set by the North American Electric Reliability Council. The PUCT has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of power supply across Texas’s main interconnected power transmission grid. The ERCOT is responsible for facilitating reliable operations of the bulk electric power supply system in the ERCOT market. Its responsibilities include ensuring that power production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers. Unlike power pools with independent operators in other regions of the country, the ERCOT market is not a centrally dispatched power pool and the ERCOT does not procure power on behalf of its members other than to maintain the reliable operations of the transmission system. The ERCOT also serves as an agent for procuring ancillary services for those who elect not to provide their own ancillary services.

 

Power sales or purchases from one location to another may be constrained by the power transfer capability between locations. Under the current ERCOT protocol, the commercially significant constraints and the transfer capabilities along these paths are reassessed every year and congestion costs are directly assigned to those parties causing the congestion. This has the potential to increase power generators’ exposure to the congestion costs associated with transferring power between zones.

 

The PUCT has adopted a rule directing the ERCOT to develop and implement a wholesale market design that, among other things, includes a day-ahead energy market and replaces the existing zonal wholesale market design with a nodal market design that is based on locational marginal prices for power. See also Regional Regulatory Developments — Texas Region. One of the stated purposes of the proposed market restructuring is to reduce local (intra-zonal) transmission congestion costs. The market redesign project is now proposed to take effect in December 2010. NRG expects that implementation of any new market design will require modifications to its existing procedures and systems. Although NRG does not expect the Company’s competitive position in the ERCOT market to be materially adversely affected by the proposed market restructuring, the Company does not know for certain how the planned market restructuring will affect its revenues, and some of NRG’s plants in the ERCOT may experience adverse pricing effects due to their location on the transmission grid.

NORTHEAST

 

NRG’s second largest asset base is located in the Northeast region of the US and is comprised of investments in generation facilities primarily located in the physical control areas of NYISO, the ISO-NE and PJM.

 

Operating Strategy

 

The Northeast region’s strategy is focused on optimizing the value of NRG’s broad and varied generation portfolio in the three interconnected and actively traded competitive markets: the NYISO, the ISO-NE and the PJM. In the Northeast markets, load-serving entities generally lack their own generation capacity, with much of the generation base aging and the current ownership of the generation highly disaggregated. Thus, commodity prices are more volatile on an as-delivered basis than in other NRG regions due to the distance and occasional physical constraints that impact the delivery of fuel into the region. In this environment, NRG seeks both to enhance its ability to be the low cost wholesale generator capable of delivering wholesale power to load centers within the region from multiple locations using multiple fuel sources, and to be properly compensated for delivering such wholesale power and related services.

 

The generation performance by fuel-type for the recent three-year period is as shown below:

 

 

NRG’s Northeast region assets are located in or near load centers and inside chronic transmission constraints such as New York City, southwestern Connecticut and the Delmarva Peninsula. Assets in these areas tend to attract higher capacity revenues and higher energy revenues and thus present opportunities for repowering these sites. The Company has benefited from the introduction of capacity market reforms in both the New England Power Pool, or NEPOOL, and PJM. The Locational Forward Reserve Markets, or LFRM, in the NEPOOL, became effective October 1, 2006, and the transition capacity payments were effective December 1, 2006. In all five LFRM auctions to date, the market has cleared at the administratively set price of $14/kw month reflecting the shortage of peaking generation especially in the Connecticut zone. The LFRM and interim capacity payments serve as a prelude to the full implementation of the Forward Capacity Market, or FCM, which begins June 1, 2010. PJM’s Reliability Pricing Model, or RPM, became effective June 1, 2007, and the Company has participated in auctions providing capacity price certainty through May 2012.

 

RMR Agreements  — Several of the Northeast region’s Connecticut assets are located in transmission-constrained load pockets and have been designated as required to be available to ISO-NE to ensure reliability. These assets are subject to Reliability-Must-Run, or RMR, agreements, which are contracts under which NRG agrees to maintain its facilities to be available to run when needed, and are paid to provide these capability services based on the Company’s costs. During 2008, Middletown, Montville and Norwalk Power (units 1 and 2) were covered by RMR agreements. Unless terminated earlier, these agreements will terminate on June 1, 2010, which coincides with the commencement of the FCM in NEPOOL.

 

Generation Facilities

 

As of December 31, 2008, NRG’s generation facilities in the Northeast region consisted of approximately 7,020 MW of generation capacity, including assets located in transmission constrained areas, such as New York City — 1,415 MW, and Southwest Connecticut — 575 MW.

The Northeast region power generation assets are summarized in the table below:

 

 

 

 

The following is a description of NRG’s most significant revenue generating plants in the Northeast region:

 

Arthur Kill  — NRG’s Arthur Kill plant is a natural gas-fired power plant consisting of three units and is located on the west side of Staten Island, New York. The plant produces an aggregate generation capacity of 865 MW from two intermediate load units (Units 20 and 30) and one peak load unit (Unit GT-1). Unit 20 produces an aggregate generation capacity of 350 MW and was installed in 1959. Unit 30 produces an aggregate generation capacity of 505 MW and was installed in 1969. Both Unit 20 and Unit 30 were converted from coal-fired to natural gas-fired facilities in the early 1990s. Unit GT-1 produces an aggregate generation capacity of 10 MW and is activated when Consolidated Edison issues a maximum generation alarm on hot days and during thunderstorms.

 

Astoria Gas Turbine  — Located in Astoria, Queens, New York, the NRG Astoria Gas Turbine facility occupies approximately 15 acres within the greater Astoria Generating complex which includes several competing generating facilities. NRG’s Astoria Gas Turbine facility has an aggregate generation capacity of approximately 550 MW from 19 operational combustion turbine generators classified into three types of turbines. The first group consists of 12 gas-fired Pratt & Whitney GG-4 Twin Packs in Buildings 2, 3 and 4, which have a net generation capacity of 145 MW per building. The second group consists of Westinghouse Industrial Combustion Turbines #191A in Buildings 5, 7 and 8 that fire on liquid distillate with a net generation capacity of approximately 12 MW per building. The third group consists of Westinghouse Industrial Gas Turbines #251GG located in Buildings 10, 11, 12 and 13 and fired on liquid distillate with a net generation capacity of 20 MW per building. The Astoria units also supply Black Start Service to the NYISO. The site also contains tankage for distillate fuel with a capacity of 86,000 barrels.

 

Dunkirk  — The Dunkirk plant is a coal-fired plant located on Lake Erie in Dunkirk, New York. This plant produces an aggregate generation capacity of 530 MW from four baseload units. Units 1 and 2 produce up to 75 MW each and were put in service in 1950, and Units 3 and 4 produce approximately 190 MW each and were put in service in 1959 and 1960, respectively. In a settlement agreement reached with the New York Department of Environmental Conservation, or NYSDEC, in January 2005, NRG committed to reducing SO ₂ emissions from

Dunkirk and Huntley stations by 86.8% below baseline emissions of 107,144 by 2013 and NO _x emissions by 80.9% below baseline emission of 17,005 by 2012. In order to comply with the NYSDEC settlement agreement, as well as with various federal and state emissions standards, the Company is in the process of installing back-end control facilities at Dunkirk that are anticipated to be completed in the fall 2009.

 

Huntley  — The Huntley plant is a coal-fired plant consisting of six units and is located in Tonawanda, New York, approximately three miles north of Buffalo. The plant has a net generation capacity of 380 MW from two baseload units (Units 67 and 68). Units 67 and 68 generate a net capacity of approximately 190 MW each, and were put in service in 1957 and 1958, respectively. Units 63 and 64 are inactive and were officially retired in May 2006. To comply with the January 2005 NYSDEC settlement agreement referenced above, NRG retired Units 65 and 66 effective June 3, 2007, and as of January 2009, has completed Huntley’s back-end control facilities.

 

Indian River  — The Indian River Power plant is a coal-fired plant located in southern Delaware on a 1,170 acre site. The plant consists of four coal-fired electric steam units (units 1 through 4) and one 15 MW combustion turbine, bringing total plant capacity to approximately 740 MW. Units 1 and 2 are each 80 MW of capacity and were placed in service in 1957 and 1959, respectively. Unit 3 is 155 MW of capacity and was placed in service in 1970, while Unit 4 is 410 MW of capacity and was placed in service in 1980. Units 1, 2, 3 and 4 are equipped with selective non-catalytic reduction systems, for the reduction of NO _x emissions. All four units are equipped with electrostatic precipitators to remove fly ash from the flue gases as well as low NO _x burners with over fired air to control NO _x emissions and activated carbon injection systems to control mercury. Units 1, 2 and 3 are fueled with eastern bituminous coal, while Unit 4 is fueled with low sulfur compliance coal. Pursuant to a consent order dated September 25, 2007, between NRG and the Delaware Department of Natural Resources and Environmental Control, or DNREC, NRG agreed to operate the units in a manner that would limit the emissions of NO _x , SO ₂ and mercury. Further, the Company agreed to mothball unit 2 by May 1, 2010, and unit 1 by May 1, 2011, and has notified PJM of the plan to mothball these units. In the absence of the appropriate control technology installed at this facility, Units 3 and 4 totaling approximately 565 MW, could not operate beyond December 31, 2011, per terms of the consent order.

 

Market Framework

 

Although each of the three Northeast Independent Systems Operators, or ISOs, and their respective energy markets are functionally, administratively and operationally independent, they all follow, to a certain extent, similar market designs. Each ISO dispatches power plants to meet system energy and reliability needs, and settles physical power deliveries at Locational Marginal Prices, or LMPs, which reflect the value of energy at a specific location at the specific time it is delivered. This value is determined by an ISO-administered auction process, which evaluates and selects the least costly supplier offers or bids to create a reliable and least-cost dispatch. The ISO-sponsored LMP energy markets consist of two separate and characteristically distinct settlement time frames. The first is a financially firm, day-ahead unit commitment market. The second is a financially settled, real-time dispatch and balancing market. Prices paid in these LMP energy markets, however, are affected by, among other things, market mitigation measures, which can result in lower prices associated with certain generating units that are mitigated because they are deemed to have locational market power.

 

SOUTH CENTRAL

 

As of December 31, 2008, NRG owned approximately 2,845 MW of generating capacity in the South Central region of the US. The region lacks a regional transmission organization or ISO and, therefore, remains a bilateral market, which is not able to take advantage of the large scale economic dispatch of an ISO-administered energy market. NRG operates the LaGen Control Area which encompasses the generating facilities and the Company’s cooperative load. As a result, the LaGen control area is capable of providing control area services, in addition to

wholesale power, that allows NRG to provide full requirement services to load-serving entities, thus making the LaGen Control Area a competitive alternative to the integrated utilities operating in the region.

 

Operating Strategy

 

The South Central region maximizes its strategic position as a significant coal-fired generator in a market that is highly dependent on natural gas for power generation. South Central also has long-term full service contracts with eleven rural cooperatives serving load across Louisiana and makes incremental wholesale energy sales when its coal-fired capacity exceeds the cooperative contract requirements. The South Central region works to expand its customer base within and beyond Louisiana and works within the confines of the Entergy Transmission System to obtain paths for incremental sales as well as secure transmission service for long-term sales or expansions.

 

The generation performance by fuel-type for the recent three-year period is as shown below:

 

 

Generation Facilities

 

NRG’s generating assets in the South Central region consist primarily of its net ownership of power generation facilities in New Roads, Louisiana, which is referred to as Big Cajun II, and also includes the Sterlington, Rockford, Bayou Cove and Big Cajun peaking facilities.

 

NRG’s power generation assets in the South Central region as of December 31, 2008, are summarized in the table below:

 

 

 

 

Big Cajun II — NRG’s Big Cajun II plant is a coal-fired, sub-critical baseload plant located along the banks of the Mississippi River, near Baton Rouge, Louisiana. This plant includes three coal-fired generation units (Units 1, 2 and 3) with an aggregate generation capacity of 1,730 MW. The plant uses coal supplied from the Powder River Basin and was commissioned between 1981 and 1983. NRG owns 100% of Units 1 and 2 and a 58% undivided interest in Unit 3 for an aggregate owned capacity of 1,490 MW of the plant. All three units have been upgraded with advanced low-NOx burners and overfire air systems.

 

Market Framework

 

NRG’s assets in the South Central region are located within the franchise territories of vertically integrated utilities, primarily Entergy Corp., or Entergy. In the South Central region, all power sales and purchases are consummated bilaterally between individual counterparties. Transacting counterparties are required to procure transmission service from the relevant transmission owners at their FERC-approved tariff rates.

 

As of December 31, 2008, NRG had long-term all-requirements contracts with eleven Louisiana distribution cooperatives with initial terms ranging from five to twenty-five years. The South Central region has seven contracts in the region that expire in 2025, with the remaining four contracts expiring between 2009 and 2014. In addition, NRG also has certain long-term contracts with the Municipal Energy Authority of Mississippi, South Mississippi Electric Power Association, Southwestern Electric Power Company and CLECO, which collectively comprised an additional 10% of the region’s contract load requirement.

 

During limited peak demand periods, the load requirements of these contract customers exceed the baseload capacity of NRG’s coal-fired Big Cajun II plant. During such peak demand periods, NRG either employs its owned or leased gas-fired assets or purchases power from external sources, frequently at higher prices than can be recovered under the Company’s contracts. As the load of the region’s customers grows and until certain of these load obligations expire, the Company can expect this imbalance to worsen, unless NRG is successful in renegotiating the terms of these long-term contracts or purchasing other low-cost generation to meet demand. NRG has to date successfully prevented the addition of large industrial or municipal loads at below-market contract rates. Also, to minimize this risk during the peak summer and winter seasons, the Company has been successful in entering into structured agreements to reduce or eliminate the need for spot market purchases.

 

WEST

 

NRG’s portfolio in the West region currently consists of the Long Beach Generating Station, the El Segundo Generating Station, the Encina Generating Station and Cabrillo II, which consists of 12 combustion turbines located in San Diego County. In addition, NRG owns a 50% interest in the Saguaro power plant located in Nevada.

 

Operating Strategy

 

NRG’s West region strategy is focused on maximizing the cash flow and value associated with its generating plants and the development of repowering projects that leverage off of existing assets and sites, as well as the preservation and ultimate realization of the commercial value of the underlying real estate. There are three principal components to this strategy: (1) capturing the value of the portfolio’s generation assets through a combination of forward contracts and market sales of capacity, energy, and ancillary services; (2) leveraging existing site control and emission allowances to permit new, more efficient generating units at existing sites; and (3) optimizing the value of the region’s coastal property for other purposes.

 

The Company’s Encina Generating Station has sold all energy and capacity, 965 MW, in the aggregate, to a load-serving entity through 2009, on a tolling basis, and recovers its operating costs plus a capacity payment. The tolling agreement includes the sale of station’s Resource Adequacy, or RA, capacity and consequently the RMR contract with the CAISO on the Encina units was terminated effective December 31, 2007. For calendar year 2008, the El Segundo station has entered into a combination of tolling and RA contracts with multiple load-serving entities and power marketers. The RA contacts covered 387 MW of the available 670 MW and the tolls covered 670 MWs during all available months. For calendar year 2009, El Segundo station entered into approximately 548 MWs RA contracts and is placing the capacity in the market through a portfolio of forward contracts. Cabrillo II sold 28 MW of RA capacity for calendar year 2008, 188 MW of RA capacity for calendar year 2009, and for the

period January 1, 2010 through November 30, 2013, 88 MW. The Cabrillo II RMR agreement was terminated on December 31 2008. Units with RA contracts also sell into energy and ancillary services markets consistent with unit availability.

 

The Saguaro power plant is located in Henderson, Nevada, and is contracted to Nevada Power and two steam hosts. The Saguaro plant is contracted to Nevada Power through 2022, one steam host, referred to as Olin (formerly known as Pioneer), whose contract was extended in 2007 for an additional two years, and a steam off-taker, Ocean Spray, whose contract runs through 2015. Saguaro Power Company, LP, the project company, procures fuel in the open market. NRG manages its share of any fuel price risk through NRG’s commodity price risk strategy.

 

 

The following are descriptions of the Company’s most significant revenue generating plants in the West region:

 

Encina — The Encina Station is located in Carlsbad, California and has a combined generating capacity of 965 MW from five fossil-fuel steam-electric generating units and one combustion turbine. The five fossil-fuel steam-electric units provide intermediate load services and use natural gas. Also located at the Encina Station is a combustion turbine that provides peaking and black-start services of 15 MW. Units 1, 2 and 3 each have a generation capacity of approximately 107 MW and were installed in 1954, 1956 and 1958, respectively. Units 4 and 5 have a generation capacity of approximately 300 MW and 330 MW respectively, and were installed in 1973 and 1978. The combustion turbine was installed in 1966. Low NOx burner modifications and SCR equipment have been installed on all the steam units.

 

El Segundo — The El Segundo plant is located in El Segundo, California and produces an aggregate generation capacity of 670 MW from two gas-fired intermediate load units (Units 3 and 4). These units, which have a generation capacity of 335 MW each, were installed in 1964 and 1965, respectively. SCR equipment has been installed on Units 3 and 4.

 

Long Beach — On August 1, 2007, the Company successfully completed and commissioned the repowering of 260 MW of gas-fired generating capacity at its Long Beach Generating Station. Generation from Long Beach provides needed support for the summer peak and during transmission contingencies to load serving entities and the California Independent System Operator. This project is backed by a 10-year PPA executed with SCE in November 2006 and effective through July 31, 2017. The new generation consists of refurbished gas turbines with SCR equipment.

 

Cabrillo II — Cabrillo II consists of 12 combustion turbines located on 4 sites throughout San Diego County with an aggregate generating capacity of approximately 190 MW. The combustion turbines were installed between 1968 and 1972 and are operated under a license agreement with SDG&E through 2013. The combustion turbines provide peaking services and serve a reliability function for the CAISO.

Market Framework

 

Except for the Saguaro facility, NRG’s generation assets in the West region operate within the balancing authority of CAISO. CAISO’s current market allows NRG’s CAISO assets to serve multiple load serving entities, or LSEs, and operates a zonal balancing market and congestion clearing mechanism. CAISO also has a locational capacity requirement, which requires LSEs to procure a significant portion of load from defined local reliability areas. All of NRG’s CAISO assets are in the Los Angeles or San Diego local reliability areas. It is expected that on April 1, 2009, CAISO’s new market, known as Market Redesign and Technology Upgrade, or MRTU, will become operational. MRTU will establish a day-ahead market for energy and ancillary services and will settle prices locationally. NRG’s CAISO assets are all peaking and intermediate in nature and are well positioned to capitalize on the higher locational prices that may result from LMPs in location constrained areas and will continue to satisfy local distribution company capacity requirements. Longer term, NRG’s California portfolio’s locational advantage may be impacted by new transmission, which may affect load pocket procurement requirements. So far, however, the impacts of increasing demand and need for flexible cycling capability combined with delays in the online date of new transmission have muted the impact of this long-term threat.

 

California’s resource mix will be significantly shaped in the years ahead by California’s renewable portfolio standard and its greenhouse gas reduction rules promulgated pursuant to Assembly Bill 32 — California Global Warming Solutions Act of 2006, or AB32. In particular, the state’s renewable portfolio standard is currently targeted at 20% for 2010 and has been set for 33% by 2020 via Executive Order. While the target requires ratification via legislation, the goal has been widely supported and is expected to create greater demand for low emission resources. The intermittent and remote nature of most renewable resources will still leave a strong demand for flexible load pocket resources. NRG’s California portfolio may also be impacted by any mechanism, such as cap-and-trade, that places a price on incremental carbon emissions. NRG’s expectation is that the emission costs will be reflected in the market price of power and that the net cost to our existing portfolio of intermediate and peaking resources will be manageable.

 

California’s investor-owned utilities are sponsoring competitive solicitations for new fossil and renewable generating capacity. NRG has submitted offers for new generation capacity to be constructed at the El Segundo and Encina sites. The new projects are in the process of obtaining necessary permits by the California Energy Commission and their respective regional air districts, and are supported by air emissions credits that have been banked after the retirement of older generating units. While neither project will be constructed without a long-term off-take agreement with a credit worthy counter-party, both projects have cost and location advantages that enhance their competitive prospects.

 

INTERNATIONAL

 

As of December 31, 2008, NRG, through certain foreign subsidiaries, had investments in power generation projects located in Australia and Germany with approximately 1,080 MW of generation capacity. In addition, NRG owns interests in coal mines located in Germany. The Company’s strategy is to maximize its return on investment and concentrate on contract management; monitoring of its facility operators to ensure safe, profitable and sustainable operations; management of cash flow and finances; and growth of its businesses through investments in projects related to current businesses.

 

NRG’s international power generation assets as of December 31, 2008, are summarized in the table below:

 

Australia  — The Gladstone power station is owned by an unincorporated joint venture. As a member of the venture, the Company owns an undivided 37.5% interest in assets of the power station and a 37.5% interest in its output. A wholly owned subsidiary, NRG Gladstone Operating Services, serves as the station’s sole operator. Because NRG is neither the majority owner nor the joint venture manager, NRG does not have unilateral control over the operation, maintenance, and management of this asset. Gladstone station’s output is fully contracted through 2029 to Boyne Smelter Limited and Stanwell Corporation Limited. Boyne Smelter is owned by a consortium whose members include all the members of the Gladstone joint venture other than NRG. Its business is to refine alumina into aluminum. Stanwell is a state owned corporation that generates power, purchases power from other generators such as Gladstone, trades power in the Australian National Electricity Market, and delivers power to retail customers.

 

On June 8, 2006, NRG announced the sale of the Company’s 37.5% interest in the joint venture and its 100% interest in NRG Gladstone Operating Services to Transfield Services Infrastructure B.V, or Transfield Services, of Australia. On October 9, 2008, Transfield Services terminated the Gladstone sale and purchase agreement at no cost or expense to the parties, other than transaction costs which are immaterial as to NRG, because of its inability to achieve necessary third party consents. Subsequent negotiations over a plan to reorganize the Gladstone project to facilitate NRG’s exit stalled due to a precipitous decline in aluminum prices and asset prices in the second half of 2008. With aluminum demand predicted by some to show little or no growth in 2009 and asset prices showing no signs of recovery, NRG’s stay in Australia may be extended. Fortunately, the long term off-take agreements will insulate the Gladstone project from the effects of the recession. The Company will aggressively pursue other options to preserve, protect and enhance the value of this investment.

 

Germany — NRG’s interests in Germany include a 50% equity interest in Mitteldeutsche Braunkohlengesellschaft mbH, or MIBRAG, which mines approximately 19 million metric tonnes of lignite per year and owns 150 MW of electric generation capacity, and a 41.9% interest in Schkopau, a 900 MW generating plant fueled with lignite from MIBRAG. NRG does not have direct operational control of either of these facilities.

 

Approximately 82% of MIBRAG’s revenues is generated from lignite sales. MIBRAG’s generation capacity comprises three plants, 33% of their output is used to power MIBRAG’s mining operations and the balance is sold, either under a contract or at spot, primarily to EnviaM, the local distribution utility. NRG, through its wholly-owned subsidiary Saale Energie GmbH, or SEG, owns 400 MW of the Schkopau plant’s electric capacity which is sold under a long-term contract to Vattenfall Europe Generation, AG.

 

Brazil  — On April 28, 2008, NRG completed the sale of its 100% interest in Tosli Acquisition B.V., or Tosli, which held all NRG’s 99.2% voting equity interest in a 156 MW hydroelectric power plant through Itiquira Energetica S.A., or ITISA, to Brookfield Renewable Power Inc. (previously Brookfield Power Inc.), a wholly-owned subsidiary of Brookfield Asset Management Inc. In addition, the purchase price adjustment contingency under the sale agreement was resolved on August 7, 2008. In connection with the sale, NRG received $300 million of cash proceeds from Brookfield, and removed $163 million of assets, including $59 million of cash, $122 million of liabilities, including $63 million of debt, and $15 million in foreign currency translation adjustment from its 2008 consolidated balance sheet. As discussed in Item 15 — Note 3, Discontinued Operations Business Acquisitions and Dispositions , to the Consolidated Financial Statements, the activities of Tosli and ITISA has been classified as discontinued operations.

 

THERMAL

 

Through its wholly-owned subsidiary, NRG Thermal LLC, or NRG Thermal, the Company owns thermal and chilled water businesses that have a steam and chilled water capacity of approximately 1,020 megawatts thermal equivalent, or MWt. As of December 31, 2008, NRG Thermal provided steam heating to approximately 505 customers and chilled water to 100 customers in five cities in the US. The Company’s thermal businesses in Pittsburgh, Harrisburg and San Francisco are regulated by their respective state Public Utility Commission. The other thermal businesses are subject to contract terms with their customers. In addition, NRG Thermal owns and operates a thermal project that serves an industrial customer with high-pressure steam. NRG Thermal also owns an 88 MW combustion turbine peaking generation facility and a 15 MW coal-fired cogeneration facility in Dover,

Delaware as well as a 12 MW gas-fired project in Harrisburg, Pennsylvania. Approximately 39% of NRG Thermal’s revenues are derived from its district heating and chilled water business in Minneapolis, Minnesota.

 

Regulatory Matters

 

As operators of power plants and participants in wholesale energy markets, certain NRG entities are subject to regulation by various federal and state government agencies. These include the CFTC, FERC, NRC, PUCT and other public utility commissions in certain states where NRG’s generating or thermal assets are located. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO markets in which it participates. NRG must also comply with the mandatory reliability requirements imposed by the North American Electric Reliability Corporation, or NERC, and the regional reliability councils in the regions where the Company operates.

 

The operations of, and wholesale electric sales from, NRG’s Texas region are not subject to rate regulation by the FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. As discussed below, these operations are subject to regulation by PUCT, as well as to regulation by the NRC with respect to the Company’s ownership interest in STP.

 

Commodities Futures Trading Commission, or CFTC

 

The CFTC, among other things, has regulatory oversight authority over the trading of electricity and gas commodities, including financial products and derivatives, under the Commodity Exchange Act, or CEA. Specifically, under existing statutory authority, CFTC has the authority to commence enforcement actions and seek injunctive relief against any person, whenever that person appears to be engaged in the communication of false or misleading or knowingly inaccurate reports concerning market information or conditions that affected or tended to affect the price of natural gas, a commodity in interstate commerce, or actions intended to or attempting to manipulate commodity markets. The CFTC also has the authority to seek civil monetary penalties, as well as the ability to make referrals to the Department of Justice for criminal prosecution, in connection with any conduct that violates the CEA. Proposals are pending in Congress to expand CFTC oversight of the over-the-counter markets and bilateral financial transactions.

 

Federal Energy Regulatory Commission

 

The FERC, among other things, regulates the transmission and the wholesale sale of electricity in interstate commerce under the authority of the Federal Power Act, or FPA. In addition, under existing regulations, the FERC determines whether an entity owning a generation facility is an Exempt Wholesale Generator, or EWG, as defined in the Public Utility Holding Company Act of 2005, or PUHCA of 2005. The FERC also determines whether a generation facility meets the ownership and technical criteria of a Qualifying Facility, or QF, under Public Utility Regulatory Policies Act of 1978, or PURPA. Each of NRG’s US generating facilities has either been determined by the FERC to qualify as a QF, or the subsidiary owning the facility has been determined to be a EWG.

 

Federal Power Act — The FPA gives the FERC exclusive rate-making jurisdiction over the wholesale sale of electricity and transmission of electricity in interstate commerce. Under the FPA, the FERC, with certain exceptions, regulates the owners of facilities used for the wholesale sale of electricity or transmission in interstate commerce as public utilities. The FPA also gives the FERC jurisdiction to review certain transactions and numerous other activities of public utilities. NRG’s QFs are currently exempt from the FERC’s rate regulation under Sections 205 and 206 of the FPA to the extent that sales are made pursuant to a state regulatory authority’s implementation of PURPA.

 

Public utilities under the FPA are required to obtain the FERC’s acceptance, pursuant to Section 205 of the FPA, of their rate schedules for the wholesale sale of electricity. All of NRG’s non-QF generating and power marketing companies in the US make sales of electricity pursuant to market-based rates authorized by the FERC. The FERC’s orders that grant NRG’s generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that NRG can exercise market power, create barriers to entry, or engage in abusive affiliate transactions. In addition, NRG’s market-based sales are subject to certain market behavior rules and, if any of its generating or power marketing companies were deemed to have violated any one of those rules, they would be subject to potential disgorgement of profits associated

with the violation and/or suspension or revocation of their market-based rate authority, as well as criminal and civil penalties. As a condition to the orders granting NRG market-based rate authority, every three years NRG is required to file a market update to demonstrate that it continues to meet the FERC’s standards with respect to generating market power and other criteria used to evaluate whether its entities qualify for market-based rates. NRG is also required to report to the FERC any material changes in status that would reflect a departure from the characteristics that the FERC relied upon when granting NRG’s various generating and power marketing companies market-based rates. If NRG’s generating and power marketing companies were to lose their market-based rate authority, such companies would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules.

 

On June 30, 2008 and December 31, 2008, NRG filed with the FERC its updated market power analyses for its Northeast and South Central assets, respectively. Such updates are a requirement of the Commission’s grant of market-based rate authority. The Company’s updates remain pending.

 

Section 203 of the FPA requires the FERC’s prior approval for the transfer of control of assets subject to the FERC’s jurisdiction. Section 204 of the FPA gives the FERC jurisdiction over a public utility’s issuance of securities or assumption of liabilities. However, the FERC typically grants blanket approval for future securities issuances and the assumption of liabilities to entities with market-based rate authority. In the event that one of NRG’s generating and power marketing companies were to lose its market-based rate authority, such company’s future securities issuances or assumption of liabilities could require prior approval from the FERC.

 

In compliance with Section 215 of the Energy Policy Act of 2005, or EPAct of 2005, the FERC has approved the NERC as the national Energy Reliability Organization, or ERO. As the ERO, NERC is responsible for the development and enforcement of mandatory reliability standards for the wholesale electric power system. NRG is responsible for complying with the standards in the regions in which it operates. As the ERO, NERC has the ability to assess financial penalties for non-compliance. In addition to complying with NERC requirements, each NRG entity must comply with the requirements of the regional reliability council for the region in which it is located.

 

Public Utility Holding Company Act of 2005 — PUHCA of 2005 provides the FERC with certain authority over and access to books and records of public utility holding companies not otherwise exempt by virtue of their ownership of EWGs, QFs, and Foreign Utility Companies, or FUCOs. NRG is a public utility holding company, but because all of the Company’s generating facilities have QF status or are owned through EWGs, it is exempt from the accounting, record retention, and reporting requirements of the PUHCA of 2005.

 

Public Utility Regulatory Policies Act — PURPA was passed in 1978 in large part to promote increased energy efficiency and development of independent power producers. PURPA created QFs to further both goals, and the FERC is primarily charged with administering PURPA as it applies to QFs. As discussed above, under current law, some categories of QFs may be exempt from regulation under the FPA as public utilities. PURPA incentives also initially included a requirement that utilities must buy and sell power to QFs. Among other things, EPAct of 2005 provides for the elimination of the obligation imposed on certain utilities to purchase power from QFs at an avoided cost rate under certain conditions. However, the purchase obligation is only eliminated if the FERC first finds that a QF has non-discriminatory access to wholesale energy markets having certain characteristics, including nondiscriminatory transmission and interconnection services provided by a regional transmission entity in certain circumstances. Existing contracts entered into under PURPA are not expected to be impacted. NRG currently owns only one QF, Saguaro Power Company, a Limited Partnership, which is interconnected to and has a contract with Nevada Power Company. Nevada Power Company is not located in a region with an ISO market.

 

Nuclear Regulatory Commission, or NRC

 

The NRC is authorized under the Atomic Energy Act of 1954, as amended, or the AEA, among other things, to grant licenses for, and regulate the operation of, commercial nuclear power reactors. As a holder of an ownership interest in STP, NRG is an NRC licensee and is subject to NRC regulation. The NRC license gives the Company the right to only possess an interest in STP but not to operate it. Operating authority under the NRC operating license for STP is held by STPNOC. NRC regulation involves licensing, inspection, enforcement, testing, evaluation, and modification of all aspects of plant design and operation including the right to order a plant shutdown, technical and

financial qualifications, and decommissioning funding assurance in light of NRC safety and environmental requirements. In addition, NRC’s written approval is required prior to a licensee transferring an interest in its license, either directly or indirectly. As a possession-only licensee, i.e., non-operating co-owner, the NRC’s regulation of NRG is primarily focused on the Company’s ability to meet its financial and decommissioning funding assurance obligations. In connection with the NRC license, the Company and its subsidiaries have a support agreement to provide up to $120 million to support operations at STP.

 

Decommissioning Trusts  — Upon expiration of the operation licenses for the two generating units at STP, currently scheduled for 2027 and 2028, the co-owners of STP are required under federal law to decontaminate and decommission the STP facility. Under NRC regulations, a power reactor licensee generally must pre-fund the full amount of its estimated NRC decommissioning obligations unless it is a rate-regulated utility, or a state or municipal entity that sets its own rates, or has the benefit of a state-mandated non-bypassable charge available to periodically fund the decommissioning trust such that the trust, plus allowable earnings, will equal the estimated decommissioning obligations by the time the decommissioning is expected to begin.

 

As a result of the acquisition of Texas Genco, NRG, through its 44% ownership interest, has become the beneficiary of decommissioning trusts that have been established to provide funding for decontamination and decommissioning of STP. CenterPoint Energy Houston Electric, LLC, or CenterPoint, and American Electric Power, or AEP, collect, through rates or other authorized charges to their electric utility customers, amounts designated for funding NRG’s portion of the decommissioning of the facility. See also Item 15 — Note 6, Nuclear Decommissioning Trust Fund, to the Consolidated Financial Statements for additional discussion.

 

In the event that the funds from the trusts are ultimately determined to be inadequate to decommission the STP facilities, the original owners of the Company’s STP interests, CenterPoint and AEP, each will be required to collect, through their PUCT-authorized non-bypassable rates or other charges to customers, additional amounts required to fund NRG’s obligations relating to the decommissioning of the facility. Following the completion of the decommissioning, if surplus funds remain in the decommissioning trusts, those excesses will be refunded to the respective rate payers of CenterPoint or AEP, or their successors.

 

Public Utility Commission of Texas, or PUCT

 

NRG’s Texas generation subsidiaries are registered as power generation companies with PUCT. The companies within the Texas region are also regulated as a Qualified Scheduling Entity. PUCT also has jurisdiction over power generation companies with regard to their sales in the wholesale markets, the implementation of measures to address undue market power or price volatility, and the administration of nuclear decommissioning trusts. The PUCT exercises its jurisdiction both directly, and indirectly, through its oversight of the ERCOT, the regional transmission organization. NRG Power Marketing, LLC, or PMI, is registered as a power marketer with the PUCT and thus is also subject to the jurisdiction of the PUCT with respect to its sales in the ERCOT.

 

Regional Regulatory Developments

 

In New England, New York, the Mid-Atlantic region, the Midwest and California, the FERC has approved regional transmission organizations, also commonly referred to as ISOs. Most of these ISOs administer a wholesale centralized bid-based spot market in their regions pursuant to tariffs approved by the FERC and associated ISO market rules. These tariffs/market rules dictate how the capacity and energy markets operate, how market participants may make bilateral sales with one another, and how entities with market-based rates are compensated within those markets. The ISOs in these regions also control access to and the operation of the transmission grid within their regions. In Texas, pursuant to a 1999 restructuring statute, the PUCT granted similar responsibilities to the ERCOT.

 

NRG is affected by rule/tariff changes that occur in the ISO regions. The ISOs that oversee most of the wholesale power markets have in the past imposed, and may in the future continue to impose, price limitations and other mechanisms to address market power or volatility in these markets. These types of price limitations and other regulatory mechanisms may adversely affect the profitability of NRG’s generation facilities that sell capacity and energy into the wholesale power markets. In addition, new approaches to the sale of electric power are being

implemented, and it is not clear whether they will operate effectively or whether they will provide adequate compensation to generators over the long-term.

 

Texas Region

 

The ERCOT has adopted “Texas Nodal Protocols” that will revise the wholesale market design to incorporate locational marginal pricing (in place of the current ERCOT zonal market). Major elements of the Texas Nodal Protocols include the continued capability for bilateral contracting of energy and ancillary services, a financially binding day-ahead market, resource-specific energy and ancillary service bid curves, the direct assignment of all congestion rents, nodal energy prices for resources, aggregation of nodal to zonal energy prices for loads, congestion revenue rights (including pre-assignment for public power entities), and pricing safeguards. The PUCT approved the Texas Nodal Protocols on April 5, 2006, and full implementation of the new market design was scheduled to begin in 2008. On May 20, 2008, the ERCOT announced that it would delay the implementation of the Texas Nodal Protocols, and is now targeting a December 2010 implementation.

 

In May 2008, the ERCOT real-time energy market experienced periods of high prices as a result of limited intervals during which two zonal constraints were simultaneously binding, and this congestion was irresolvable through the dispatch of available resources. In response, the ERCOT enacted revised protocols, effective June 9, 2008, for addressing such zonal congestion, providing the ERCOT with greater authority to manage such congestion through the use of out-of-market mechanisms towards the goal of lowering prices. In addition, on June 17, 2008, the ERCOT enacted revisions to its price cap procedures in order to further dampen the volatility and high prices. Thus, it is unlikely that the circumstances contributing to the price spikes of May 2008 will be repeated.

 

On July 17, 2008, as part of its determination of Competitive Renewable Energy Zones, or CREZ, the PUCT approved a significant transmission expansion plan to provide for the delivery of approximately 18,500 MW of energy from the western region of Texas, primarily wind generation. The schedule for construction of the transmission upgrades (approximately 2,300 miles of new 345 kV lines and 42 miles of new 138 kV lines) will be determined in subsequent PUCT proceedings. If completed as currently approved, the transmission upgrades and associated wind generation could impact wholesale energy and ancillary service prices in the ERCOT. The PUCT issued its written order on August 15, 2008.

 

Northeast Region

 

New England — NRG’s Middletown and Montville facilities continue to be operated pursuant to RMR agreements that were accepted by the Commission on February 1, 2006 (effective January 1, 2006). Unless terminated earlier, the Middletown and Montville RMR agreements will terminate upon the commencement of the FCM as discussed below. NRG’s Norwalk Power facility units 1 and 2 continue to be operated pursuant to an RMR agreement that was accepted by the Commission on July 16, 2007 (effective June 19, 2007). On December 4, 2008, Norwalk Power filed a Settlement Agreement resolving the RMR agreement eligibility and rate issues. The Settlement Agreement provides for an Annual Fixed Revenue Requirement of $34 million for 2008 and $32 million for 2009, continuing at a rate of $32 million per year until FCM is implemented on June 1, 2010. The FERC accepted the Settlement Agreement on December 30, 2008. In the FCM auction for delivery year 2010/2011, the Company sought to de-list Norwalk Power’s units 1 and 2. ISO-NE declined to accept that de-list bid on the grounds these units were needed for reliability. The FERC has determined that the units should be compensated at their de-list bid of $5.99 per kW-month. The Company did not seek to de-list Norwalk Power’s units 1 and 2 in the FCM auction for delivery year 2011/2012.

 

On December 28, 2006, the Attorneys General of the State of Connecticut and Commonwealth of Massachusetts filed in the US Court of Appeals for the District of Columbia, or D.C., Circuit an appeal of the FERC orders accepting the settlement of the New England capacity market design. The settlement, filed March 7, 2006, by a broad group of New England market participants, provides for interim capacity transition payments for all generators in New England for the period starting December 1, 2006 through May 31, 2010, and the establishment of a FCM commencing May 31, 2010. On June 16, 2006, the FERC issued an order accepting the settlement, which was reaffirmed on rehearing by order dated October 31, 2006. Interim capacity transition payments provided for under the FCM settlement commenced December 1, 2006, as scheduled. The first FCM

auction for the 2010/2011 delivery year was concluded on February 6, 2008, and bidding reached the minimum floor price of $4.50 per kW-month. A successful appeal by the Attorneys General could disturb the settlement and create a refund obligation of interim capacity transition payments. Oral arguments were held on February 14, 2008.

 

On October 20, 2008, Northeast Utilities Service Company, or NU, the parent company of CL&P filed an application with the Connecticut Siting Council for the Greater Springfield Reliability component of the New England East-West Solution, or NEEWS, transmission project, four distinct projects that together represent a significant reinforcement of the 345 kV transmission system. If constructed, the NEEWS projects will increase the import capacity into Connecticut by approximately 1,100 MW.

 

New York — On March 7, 2008, the FERC issued an order accepting the NYISO’s proposed market reforms to the in-city Installed Capacity, or ICAP, market, with only minor modifications. The NYISO proposal retains the existing ICAP market structure, but imposes additional market power mitigation on the current owners of Consolidated Edison’s divested generation units in New York City (which include NRG’s Arthur Kill and Astoria facilities), who are deemed to be pivotal suppliers. Specifically, the NYISO proposal imposes a new reference price on pivotal suppliers and requires bids to be submitted at or below the reference price. The new reference price is derived from the expected clearing price based upon the intersection of the supply curve and the ICAP Demand Curve if all suppliers bid as price-takers. The NYISO’s proposed reforms became effective March 27, 2008.

 

The state-wide Installed Reserve Margin, or IRM, is set annually by the New York State Reliability Council, or NYSRC, and affects the overall demand for capacity in the New York market. The NYSRC approved a 2009 IRM of 16.5%, which is an increase of 1.5% from the 2008 requirement and should have a modest positive effect on capacity prices. Additionally, on January 29, 2008, the FERC accepted the NYISO’s installed capacity demand curves for 2008/2009, 2009/2010, and 2010/2011. The demand curves are a critical determinant of capacity market prices, and these revised curves will contribute to the continuation of the current depressed prices, all other factors remaining constant.

 

PJM — On December 12, 2008, PJM filed with the FERC a number of proposed revisions to the RPM capacity market design. PJM has proposed to implement many of the more significant changes in the next RPM Base Residual Auction, scheduled for May 2009 for planning year 2012/2013. On February 9, 2009 PJM filed an Offer of Settlement revising its December 12, 2008 filing with respect to the determination of several of the key inputs for the RPM auctions.

 

West Region

 

California has transitioned to a market structure where LSEs have an obligation to procure a portion of their Resource Adequacy, or RA, capacity requirements in transmission-constrained areas. All of NRG’s California assets operate in one or more of these constrained areas. This local procurement obligation is leading to a phase-out of RMR agreements with the CAISO. Cabrillo Power II LLC terminated its RMR agreement with CAISO effective December 31, 2008. See also the Regional Business Description for a discussion of the contracting activities that have occurred on the units pursuant to the state’s RA program.

 

CAISO has indicated that MRTU is scheduled to commence April 1, 2009. Significant components of the MRTU include: (i) locational marginal pricing of energy; (ii) a more effective congestion management system; (iii) a day-ahead market; and (iv) an increase to the existing bid caps. NRG considers these market reforms to be a positive development for its assets in the region. On October 18, 2008, the FERC accepted the CAISO’s Interim Capacity Procurement Mechanism, scheduled to go into effect contemporaneously with the implementation of MRTU. This mechanism is not a capacity market, but rather allows the CAISO to acquire generation capacity if LSEs do not satisfy their Resource Adequacy Obligations.

 

On October 22, 2008, the FERC issued a definitive order regarding the provision of station power in California. The FERC’s order reaffirmed the right of generators to engage in monthly netting of their station power needs and, further, clarified that local transmission-owning utilities are preempted from imposing state-based charges on such generators. This order should allow the Company to engage in monthly netting and thus avoid buying power at retail for many of its stations and, further, to avoid the other charges that the local transmission-owning utilities have been

imposing. The Company has submitted a station power plan to the California Public Utilities Commission, or CPUC, and expects to realize savings in operation costs as a result of this order.

 

See also Item 15 — Note 22, Regulatory Matters, to the Consolidated Financial Statements for a further discussion.

 

Environmental Matters

 

NRG is subject to a wide range of environmental regulations across a broad number of jurisdictions in the development, ownership, construction and operation of domestic and international projects. These laws and regulations generally require that governmental permits and approvals be obtained before construction and during operation of power plants. Environmental laws have become increasingly stringent in recent years, especially around the regulation of air emissions from power generators. Such laws generally require regular capital expenditures for power plant upgrades, modifications and the installation of certain pollution control equipment. In general, future laws and regulations are expected to require the addition of emission controls or other environmental quality equipment or the imposition of certain restrictions on the operations of the Company’s facilities. NRG expects that future liability under, or compliance with, environmental requirements could have a material effect on the Company’s operations or competitive position.

 

Federal Environmental Initiatives

 

Air — On May 18, 2005, the USEPA published the Clean Air Mercury Rule, or CAMR, and the Clean Air Interstate Rule, or CAIR, market-based cap-and-trade programs to reduce mercury, SO ₂ and NOx emissions from coal-fired power plants. On February 8, 2008, the US Court of Appeals for the D.C. Circuit vacated the USEPA’s rule delisting coal- and oil-fired electric generating units on which CAMR was based. Power plant mercury emissions are now subject to Section 112 of the Clean Air Act, or CAA, which requires installation of maximum achievable control technology, or MACT, to reduce emissions. On October 17, 2008, the USEPA filed a petition with the US Supreme Court to reconsider the vacatur which was immediately followed by a petition to force EPA to issue the MACT standard from environmental groups. Certain states in which NRG operates coal plants, such as the states of Delaware, Massachusetts and New York, adopted state implementation plans in lieu of the CAMR federal implementation plan. These state rules remain unchanged by the Court’s ruling and are likely to meet any new standard for MACT requirements at existing generating units.

 

CAIR applied to 28 eastern states and D.C., and capped both SO ₂ and NOx emissions from power plants in two phases. CAIR applies to most of the Company’s power plants in the states of New York, Massachusetts, Connecticut, Delaware, Louisiana, Illinois, Pennsylvania, Maryland and Texas. Following a finding to vacate CAIR in its entirety in July 2008, the D.C. Circuit Court reversed its opinion in December 2008 and remanded CAIR to the USEPA without vacatur. As a result, the effective date for the CAIR NOx trading program remains January 1, 2009. NRG’s SO ₂ and NOx control plans are driven primarily by state requirements and consent orders. NRG’s estimate for environmental capital expenditures reflects changes in schedule and design related to the current status of both CAIR and CAMR. The timing and substantive provisions of any ensuing revised or replacement regulations or legislation may alter the composition and/or rate of spending for environmental retrofits at the Company’s facilities.

 

In a ruling on December 22, 2006, the D.C. Circuit overturned portions of the USEPA’s Phase I implementation rule for the new 8-hour ozone standard. Specifically, the court ruled that the USEPA could revoke the 1-hour standard as long as there was no backsliding from more stringent control measures. This ruling could result in the imposition of fees under Section 185 of the CAA on volatile organic carbon, or VOC, and NOx emissions in severe non-attainment areas. The fees could be as high as $7,700/ton for emissions above 80% of baseline emissions levels. Depending on the determination of baseline emission levels, this could materially impact NRG’s operations in Los Angeles, New York City Area and Houston.

 

The USEPA strengthened the primary and secondary ground level ozone National Ambient Air Quality Standards, or NAAQS, (eight hour average) from 0.08 ppm to 0.075 ppm on March 12, 2008. The USEPA plans to finalize ozone non-attainment regions by March 2010 and states would likely submit plans to come into attainment

by 2013. The Company is unable to predict with certainty the impact of the states’ future recommendations on NRG’s operations.

 

In the 1990s, the USEPA commenced an industry-wide investigation of coal-fired electric generators to determine compliance with environmental requirements under the CAA associated with repairs, maintenance, modifications and operational changes made to facilities over the years. As a result, the USEPA and several states filed suits against a number of coal-fired power plants in mid-western and southern states alleging violations of the CAA New Source Review, or NSR, and Prevention of Significant Deterioration, or PSD, requirements. The USEPA has issued a Notice of Violation, or NOV, against NRG’s Big Cajun II plant alleging that NRG’s predecessors had undertaken projects that triggered requirements under the PSD program, including the installation of emission controls. NRG has evaluated the claims and believes they have no merit. Nonetheless, NRG has had discussions with the USEPA about resolving the claims. See the South Central region below for a further discussion.

 

Climate Change — At the national level and at various regional and state levels, policies are under development to regulate GHG emissions, thereby effectively putting a cost on such emissions in order to create financial incentives to reduce them. In addition, earlier this year, the US Supreme Court found that CO ₂ , the most common GHG, could be regulated as a pollutant and that the USEPA, under the CAA, could regulate CO ₂ emissions from mobile sources and by extension, stationary sources. The USEPA gathered input from stakeholders in the fall of 2008, but has not taken any action to regulate CO ₂ under the CAA. Since power plants, particularly coal-fired plants, are a significant source of GHG emissions both in the US and globally, it is almost certain that GHG legislative or regulatory actions will encompass power plants as well as other GHG emitting stationary sources.

 

In 2008, in the course of producing approximately 80 million MWh of electricity, NRG’s power plants emitted 68 million tonnes of CO ₂ , of which 61 million tonnes were emitted in the US, 4 million tonnes in Germany and 3 million tonnes in Australia. The impact from federal, regional or state regulation of GHGs on the Company’s financial performance will depend on a number of factors, including the overall level of GHG reductions required under any such regulations, the price and availability of offsets, and the extent to which NRG would be entitled to receive CO ₂ emissions allowances without having to purchase them in an auction or on the open market. Thereafter, under any such legislation or regulation, the impact on NRG would depend on the Company’s level of success in developing and deploying low and no carbon technologies such as those being pursued as part of the Repowering NRG and econrg initiatives. Additionally, NRG’s current contracts with its South Central region’s cooperative customers allows for the recovery of emission-based costs.

 

Water — In July 2004, the USEPA published rules governing cooling water intake structures at existing power facilities commonly referred to as the Phase II 316(b) rules. These rules specify standards for cooling water intake structures at existing power plants using the largest amounts of cooling water. These rules will require implementation of the Best Technology Available, or BTA, for minimizing adverse environmental impacts unless a facility shows that such standards would result in very high costs or little environmental benefit. On January 25, 2007, the Second Circuit Court of Appeals made its decision in the Riverkeeper vs. USEPA appeal over the Phase II 316(b) regulation. Riverkeeper prevailed on nearly all issues and the decision essentially remands all of the important aspects of the rule back to the USEPA for reconsideration. In July 2007, the USEPA suspended the rule, except for the requirement that permitting agencies develop best professional judgment controls for existing facility cooling water intake structures that reflect the best technology available for minimizing adverse environmental impact. The Second Circuit Court of Appeals decision has been challenged in the US Supreme Court. The Phase II 316(b) rule affects a number of NRG’s plants, specifically those with once-through cooling systems. While NRG has included the capital costs associated with the rule within the Company’s estimated environmental capital expenditures based on good faith estimates, until the USEPA has concluded its reconsideration of the Phase II 316(b) rules, it is not possible to estimate with certainty the capital costs that will be required for compliance with the Phase II 316(b) rules.

 

Nuclear Waste — Under the US Nuclear Waste Policy Act of 1982, the federal government must remove and ultimately dispose of spent nuclear fuel and high-level radioactive waste from nuclear plants. Consistent with the US Nuclear Waste Policy Act of 1982, owners of nuclear plants, including the owners of STP, entered into contracts setting out the obligations of the owners and the US Department of Energy, or DOE, including the fees to be paid by the owners for DOE’s services. Since 1998, the DOE has been in default on its obligations to begin removing spent

nuclear fuel and high-level radioactive waste from reactors. On January 28, 2004, the owners of STP filed a breach of contract suit against the DOE in order to protect against the running of a statute of limitations.

 

Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended, the state of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. In 2003, the state of Texas enacted legislation allowing a private entity to be licensed to accept low-level radioactive waste for disposal. NRG intends to continue to ship low-level waste material from STP offsite for as long as an alternative disposal site is available. Should existing off-site disposal become unavailable, the low-level waste material will then be stored on-site. STP’s on-site storage capacity is expected to be adequate for STP’s needs until other off-site facilities become available.

 

Regional US Environmental Initiatives

 

Northeast Region

 

NRG operates electric generating units located in Connecticut, Delaware, Maryland, Massachusetts and New York which are subject to RGGI. These units will have to surrender one allowance for every US ton of CO ₂ emitted with true up for 2009-2011 occurring in 2012. Allowances will be partially allocated in the state of Delaware only. In 2008, NRG emitted approximately 12 million tonnes of CO ₂ in RGGI states.

 

West Region

 

Under AB32, which was enacted in 2007, the state of California will launch a multi sector climate change program which likely will include, among other things, a phased cap-and-trade approach starting in 2012 and an increased use of renewable energy. The AB32 scoping document, adopted by the California Air Resources Board or CARB in December 2008 is consistent with the trading approach of the Western Climate Initiative or WCI, made up of seven states and four Canadian Provinces. NRG does not expect any implementation of cap-and-trade under AB32 in California to have a significant adverse financial impact on the Company for a variety of reasons, including the fact that NRG’s California portfolio consists of natural gas-fired peaking facilities and will likely be able to pass through any costs of purchasing allowances in power prices.

 

South Central Region

 

On January 27, 2004, NRG’s Louisiana Generating, LLC and the Company’s Big Cajun II plant received a request under Section 114 of the CAA from the USEPA seeking information primarily related to physical changes made at the Big Cajun II plant, and subsequently received a NOV on February 15, 2005, alleging that NRG’s predecessors had undertaken projects that triggered requirements under the Prevention of Significant Deterioration program, including the installation of emission controls. NRG submitted multiple responses commencing February 27, 2004 and ending on October 20, 2004. On May 9, 2006, these entities received from the Department of Justice, or DOJ, a Notice of Deficiency related to their responses, to which NRG responded on May 22, 2006. A document review was conducted at NRG’s Louisiana Generating, LLC offices by the DOJ during the week of August 14, 2006. On December 8, 2006, the USEPA issued a supplemental NOV updating the original February 15, 2005 NOV. NRG has evaluated the original and subsequent claims and believes they have no merit. Nonetheless, NRG has had discussions with the USEPA about resolving the claims and the Company cannot predict with certainty the outcome of this matter.

 

Domestic Site Remediation Matters

 

Under certain federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products at the facility. NRG may also be held liable to a governmental entity or to third parties for property damage, personal injury and investigation and remediation costs incurred by a party in connection with hazardous material releases or threatened releases. These laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, as amended by the Superfund Amendments and Reauthorization Act of 1986, or SARA, impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and the

courts have interpreted liability under such laws to be strict (without fault) and joint and several. Cleanup obligations can often be triggered during the closure or decommissioning of a facility, in addition to spills or other occurrences during its operations.

 

In January 2006, NRG’s Indian River Operations, Inc. received a letter of informal notification from the DNREC stating that it may be a potentially responsible party with respect to a historic captive landfill. On October 1, 2007, NRG signed an agreement with the DNREC to investigate the site through the Voluntary Clean-up Program. On February 4, 2008, the DNREC issued findings that no further action is required in relation to surface water and that a previously planned shoreline stabilization project would adequately address shore line erosion. The landfill itself will require a further Remedial Investigation and Feasibility Study to determine the type and scope of any additional work required. Until the Remedial Investigation and Feasibility Study are completed, the Company is unable to predict the impact of any required remediation.

 

On May 29, 2008, the DNREC issued an invitation to NRG’s Indian River Operations, Inc. to participate in the development and performance of a Natural Resource Damage Assessment, or NRDA, at the Burton Island Old Ash Landfill. NRG is currently working with the DNREC and other Trustees to close out the property.

 

Further details regarding the Company’s Domestic Site Remediation obligations can be found in Item 15 — Note 23, Environmental Matters , to the Consolidated Financial Statements.

 

International Environmental Matters

 

Most of the foreign countries in which NRG owns or may acquire or develop independent power projects have environmental and safety laws or regulations relating to the ownership or operation of electric power generation facilities. These laws and regulations, like those in the US, are constantly evolving and have a significant impact on international wholesale power producers. In particular, NRG’s international power generation facilities will likely be affected by emissions limitations and operational requirements imposed by the Kyoto Protocol, an international treaty related to greenhouse gas emissions enacted on February 16, 2005, as well as country-based restrictions pertaining to global climate change concerns.

 

NRG retains appropriate advisors in foreign countries and seeks to design its international asset management strategy to comply with each country’s environmental and safety laws and regulations. There can be no assurance that changes in such laws or regulations will not adversely affect the Company’s international operations.

 

MIBRAG/Schkopau, Germany  — Under the German National CO ₂ Allocation Plan 2008 — 2012, MIBRAG was granted CO ₂ allocations that are less than the needs of its three generating plants. MIBRAG has minimized the impact of the short allocation by coordinated forward selling of electricity and purchase of CO ₂ certificates at times when the CO ₂  / electricity spread is profitable. Additionally, MIBRAG has submitted an application under the hardship clause of the law to receive a higher allocation of the CO ₂ allowances. The cost of compliance with the CO ₂ regulation for NRG’s Schkopau plant is passed through to its off-taker of energy under terms of its existing PPA.

 

Gladstone, Australia — On December 3, 2007, Australia ratified the Kyoto Protocol that commits to targets for GHG reductions. Australia also set a target to reduce greenhouse gas emissions to 60% of 2000 levels by 2050. The government is establishing a single national system for reporting of GHG, abatement actions, and energy consumption and generation starting July 1, 2008. This will underpin the Australian Emissions Trading Scheme, currently in the early stages of design that will be operational no later than 2010.

 

Available Information

 

NRG’s annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, or Exchange Act, are available free of charge through the Company’s website, www.nrgenergy.com , as soon as reasonably practicable after they are electronically filed with, or furnished to the SEC.

 

Many of NRG’s power generation facilities operate, wholly or partially, without long-term power sale agreements.

 

Many of NRG’s facilities operate as “merchant” facilities without long-term power sales agreements for some or all of their generating capacity and output, and therefore are exposed to market fluctuations. Without the benefit of long-term power sales agreements for these assets, NRG cannot be sure that it will be able to sell any or all of the power generated by these facilities at commercially attractive rates or that these facilities will be able to operate profitably. This could lead to future impairments of the Company’s property, plant and equipment or to the closing of certain of its facilities, resulting in economic losses and liabilities, which could have a material adverse effect on the Company’s results of operations, financial condition or cash flows.

 

NRG’s financial performance may be impacted by changing natural gas prices, significant and unpredictable price fluctuations in the wholesale power markets and other market factors that are beyond the Company’s control.

 

A significant percentage of the Company’s domestic revenues are derived from baseload power plants that are fueled by coal. In many of the competitive markets where NRG operates, the price of power typically is set by natural gas-fired power plants that currently have substantially higher variable costs than NRG’s coal-fired baseload power plants. This allows the Company’s baseload coal generation assets to earn attractive operating margins compared to plants fueled by natural gas. A decrease in natural gas prices could result in a corresponding decrease in the market price of power that could significantly reduce the operating margins of the Company’s baseload generation assets and materially and adversely impact its financial performance.

 

In addition, because changes in power prices in the markets where NRG operates are generally correlated with changes in natural gas prices, NRG’s hedging portfolio includes natural gas derivative instruments to hedge power prices for its baseload generation. If this correlation between power prices and natural gas prices is not maintained and a change in gas prices is not proportionately offset by a change in power prices, the Company’s natural gas hedges may not fully cover this differential. This could have a material adverse impact on the Company’s cash flow and financial position.

 

Market prices for power, capacity and ancillary services tend to fluctuate substantially. Unlike most other commodities, electric power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility from supply and demand imbalances, especially in the day-ahead and spot markets. Long- and short-term power prices may also fluctuate substantially due to other factors outside of the Company’s control, including:

 

 

These factors have caused the Company’s operating results to fluctuate in the past and will continue to cause them to do so in the future.

 

NRG’s costs, results of operations, financial condition and cash flows could be adversely impacted by disruption of its fuel supplies.

 

NRG relies on coal, oil and natural gas to fuel a majority of its power generation facilities. Delivery of these fuels to the facilities is dependent upon the continuing financial viability of contractual counterparties as well as upon the infrastructure (including rail lines, rail cars, barge facilities, roadways, and natural gas pipelines) available to serve each generation facility. As a result, the Company is subject to the risks of disruptions or curtailments in the production of power at its generation facilities if a counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure.

 

NRG has sold forward a substantial portion of its baseload power in order to lock in long-term prices that it deemed to be favorable at the time it entered into the forward sale contracts. In order to hedge its obligations under these forward power sales contracts, the Company has entered into long-term and short-term contracts for the purchase and delivery of fuel. Many of the forward power sales contracts do not allow the Company to pass through changes in fuel costs or discharge the power sale obligations in the case of a disruption in fuel supply due to force majeure events or the default of a fuel supplier or transporter. Disruptions in the Company’s fuel supplies may therefore require it to find alternative fuel sources at higher costs, to find other sources of power to deliver to counterparties at a higher cost, or to pay damages to counterparties for failure to deliver power as contracted. Any such event could have a material adverse effect on the Company’s financial performance.

 

NRG also buys significant quantities of fuel on a short-term or spot market basis. Prices for all of the Company’s fuels fluctuate, sometimes rising or falling significantly over a relatively short period of time. The price NRG can obtain for the sale of energy may not rise at the same rate, or may not rise at all, to match a rise in fuel or delivery costs. This may have a material adverse effect on the Company’s financial performance. Changes in market prices for natural gas, coal and oil may result from the following:

 

 

NRG’s plant operating characteristics and equipment, particularly at its coal-fired plants, often dictate the specific fuel quality to be combusted. The availability and price of specific fuel qualities may vary due to supplier financial or operational disruptions, transportation disruptions and force majeure. At times, coal of specific quality may not be available at any price, or the Company may not be able to transport such coal to its facilities on a timely basis. In this case, the Company may not be able to run the coal facility even if it would be profitable. Operating a coal facility with different quality coal can lead to emission or operating problems. If the Company had sold forward the power from such a coal facility, it could be required to supply or purchase power from alternate sources, perhaps at a loss. This could have a material adverse impact on the financial results of specific plants and on the Company’s results of operations.

There may be periods when NRG will not be able to meet its commitments under forward sale obligations at a reasonable cost or at all.

 

A substantial portion of the output from NRG’s baseload facilities has been sold forward under fixed price power sales contracts through 2014, and the Company also sells forward the output from its intermediate and peaking facilities when its deems it commercially advantageous to do so. Because the obligations under most of these agreements are not contingent on a unit being available to generate power, NRG is generally required to deliver power to the buyer, even in the event of a plant outage, fuel supply disruption or a reduction in the available capacity of the unit. To the extent that the Company does not have sufficient lower cost capacity to meet its commitments under its forward sale obligations, the Company would be required to supply replacement power either by running its other, higher cost power plants or by obtaining power from third-party sources at market prices that could substantially exceed the contract price. If NRG fails to deliver the contracted power, it would be required to pay the difference between the market price at the delivery point and the contract price, and the amount of such payments could be substantial.

 

In the South Central region, NRG has long-term contracts with rural cooperatives that require it to serve all of the cooperatives’ requirements at prices that generally reflect the costs of coal-fired generation. At times, the output from NRG’s coal-fired Big Cajun II facility has been and will continue to be inadequate to serve these obligations, and when that happens the Company has typically purchased power from other power producers, often at a loss. NRG’s financial returns from its South Central region could deteriorate over time if the rural cooperatives significantly grow their customer base during the remaining terms of these contracts unless the Company is able to amend or renegotiate its contracts with the cooperatives or add generating capacity.

 

NRG’s trading operations and the use of hedging agreements could result in financial losses that negatively impact its results of operations.

 

The Company typically enters into hedging agreements, including contracts to purchase or sell commodities at future dates and at fixed prices, in order to manage the commodity price risks inherent in its power generation operations. These activities, although intended to mitigate price volatility, expose the Company to other risks. When the Company sells power forward, it gives up the opportunity to sell power at higher prices in the future, which not only may result in lost opportunity costs but also may require the Company to post significant amounts of cash collateral or other credit support to its counterparties. The Company also relies on counterparty performance under its hedging agreements and is exposed to the credit quality of its counterparties under those agreements. Further, if the values of the financial contracts change in a manner that the Company does not anticipate, or if a counterparty fails to perform under a contract, it could harm the Company’s business, operating results or financial position.

 

NRG does not typically hedge the entire exposure of its operations against commodity price volatility. To the extent it does not hedge against commodity price volatility, the Company’s results of operations and financial position may be improved or diminished based upon movement in commodity prices.

 

NRG may engage in trading activities, including the trading of power, fuel and emissions allowances that are not directly related to the operation of the Company’s generation facilities or the management of related risks. These trading activities take place in volatile markets and some of these trades could be characterized as speculative. The Company would expect to settle these trades financially rather than through the production of power or the delivery of fuel. This trading activity may expose the Company to the risk of significant financial losses which could have a material adverse effect on its business and financial condition.

 

NRG may not have sufficient liquidity to hedge market risks effectively.

 

The Company is exposed to market risks through its power marketing business, which involves the sale of energy, capacity and related products and the purchase and sale of fuel, transmission services and emission allowances. These market risks include, among other risks, volatility arising from location and timing differences that may be associated with buying and transporting fuel, converting fuel into energy and delivering the energy to a buyer.

NRG undertakes these marketing activities through agreements with various counterparties. Many of the Company’s agreements with counterparties include provisions that require the Company to provide guarantees, offset of netting arrangements, letters of credit, a first or second lien on assets and/or cash collateral to protect the counterparties against the risk of the Company’s default or insolvency. The amount of such credit support that must be provided typically is based on the difference between the price of the commodity in a given contract and the market price of the commodity. Significant movements in market prices can result in the Company being required to provide cash collateral and letters of credit in very large amounts. The effectiveness of the Company’s strategy may be dependent on the amount of collateral available to enter into or maintain these contracts, and liquidity requirements may be greater than the Company anticipates or will be able to meet. Without a sufficient amount of working capital to post as collateral in support of performance guarantees or as a cash margin, the Company may not be able to manage price volatility effectively or to implement its strategy. An increase in the amount of letters of credit or cash collateral required to be provided to the Company’s counterparties may negatively affect the Company’s liquidity and financial condition.

 

Further, if any of NRG’s facilities experience unplanned outages, the Company may be required to procure replacement power at spot market prices in order to fulfill contractual commitments. Without adequate liquidity to meet margin and collateral requirements, the Company may be exposed to significant losses, may miss significant opportunities, and may have increased exposure to the volatility of spot markets.

 

The accounting for NRG’s hedging activities may increase the volatility in the Company’s quarterly and annual financial results.

 

NRG engages in commodity-related marketing and price-risk management activities in order to financially hedge its exposure to market risk with respect to electricity sales from its generation assets, fuel utilized by those assets and emission allowances.

 

NRG generally attempts to balance its fixed-price physical and financial purchases and sales commitments in terms of contract volumes and the timing of performance and delivery obligations through the use of financial and physical derivative contracts. These derivatives are accounted for in accordance with SFAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended, or SFAS 133, which requires the Company to record all derivatives on the balance sheet at fair value with changes in the fair value resulting from fluctuations in the underlying commodity prices immediately recognized in earnings, unless the derivative qualifies for cash flow hedge accounting treatment. Whether a derivative qualifies for cash flow hedge accounting treatment depends upon it meeting specific criteria used to determine if the cash flow hedge is and will remain appropriate for the term of the derivative. All economic hedges may not necessarily qualify for cash flow hedge accounting treatment. As a result, the Company’s quarterly and annual results are subject to significant fluctuations caused by changes in market prices.

 

Competition in wholesale power markets may have a material adverse effect on NRG’s results of operations, cash flows and the market value of its assets.

 

NRG has numerous competitors in all aspects of its business, and additional competitors may enter the industry. Because many of the Company’s facilities are old, newer plants owned by the Company’s competitors are often more efficient than NRG’s aging plants, which may put some of these plants at a competitive disadvantage to the extent the Company’s competitors are able to consume the same or less fuel as the Company’s plants consume. Over time, the Company’s plants may be squeezed out of their markets, or may be unable to compete with these more efficient plants.

 

In NRG’s power marketing and commercial operations, it competes on the basis of its relative skills, financial position and access to capital with other providers of electric energy in the procurement of fuel and transportation services, and the sale of capacity, energy and related products. In order to compete successfully, the Company seeks to aggregate fuel supplies at competitive prices from different sources and locations and to efficiently utilize transportation services from third-party pipelines, railways and other fuel transporters and transmission services from electric utilities.

 

Other companies with which NRG competes with may have greater liquidity, greater access to credit and other financial resources, lower cost structures, more effective risk management policies and procedures, greater ability

to incur losses, longer-standing relationships with customers, greater potential for profitability from ancillary services or greater flexibility in the timing of their sale of generation capacity and ancillary services than NRG does.

 

NRG’s competitors may be able to respond more quickly to new laws or regulations or emerging technologies, or to devote greater resources to the construction, expansion or refurbishment of their power generation facilities than NRG can. In addition, current and potential competitors may make strategic acquisitions or establish cooperative relationships among themselves or with third parties. Accordingly, it is possible that new competitors or alliances among current and new competitors may emerge and rapidly gain significant market share. There can be no assurance that NRG will be able to compete successfully against current and future competitors, and any failure to do so would have a material adverse effect on the Company’s business, financial condition, results of operations and cash flow.

 

Operation of power generation facilities involves significant risks and hazards customary to the power industry that could have a material adverse effect on NRG’s revenues and results of operations. NRG may not have adequate insurance to cover these risks and hazards.

 

The ongoing operation of NRG’s facilities involves risks that include the breakdown or failure of equipment or processes, performance below expected levels of output or efficiency and the inability to transport the Company’s product to its customers in an efficient manner due to a lack of transmission capacity. Unplanned outages of generating units, including extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of the Company’s business. Unplanned outages typically increase the Company’s operation and maintenance expenses and may reduce the Company’s revenues as a result of selling fewer MWh or require NRG to incur significant costs as a result of running one of its higher cost units or obtaining replacement power from third parties in the open market to satisfy the Company’s forward power sales obligations. NRG’s inability to operate the Company’s plants efficiently, manage capital expenditures and costs, and generate earnings and cash flow from the Company’s asset-based businesses could have a material adverse effect on the Company’s results of operations, financial condition or cash flows. While NRG maintains insurance, obtains warranties from vendors and obligates contractors to meet certain performance levels, the proceeds of such insurance, warranties or performance guarantees may not be adequate to cover the Company’s lost revenues, increased expenses or liquidated damages payments should the Company experience equipment breakdown or non-performance by contractors or vendors.

 

Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks such as earthquake, flood, lightning, hurricane and wind, other hazards, such as fire, explosion, structural collapse and machinery failure are inherent risks in the Company’s operations. These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in NRG being named as a defendant in lawsuits asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties. NRG maintains an amount of insurance protection that it considers adequate, but the Company cannot provide any assurance that its insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which it may be subject. A successful claim for which the Company is not fully insured could hurt its financial results and materially harm NRG’s financial condition. Further, due to rising insurance costs and changes in the insurance markets, NRG cannot provide any assurance that its insurance coverage will continue to be available at all or at rates or on terms similar to those presently available. Any losses not covered by insurance could have a material adverse effect on the Company’s financial condition, results of operations or cash flows.

 

Maintenance, expansion and refurbishment of power generation facilities involve significant risks that could result in unplanned power outages or reduced output and could have a material adverse effect on NRG’s results of operations, cash flow and financial condition.

 

Many of NRG’s facilities are old and require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures could result in reduced profitability.

NRG cannot be certain of the level of capital expenditures that will be required due to changing environmental and safety laws and regulations (including changes in the interpretation or enforcement thereof), needed facility repairs and unexpected events (such as natural disasters or terrorist attacks). The unexpected requirement of large capital expenditures could have a material adverse effect on the Company’s liquidity and financial condition.

 

If NRG makes any major modifications to its power generation facilities, the Company may be required to install the best available control technology or to achieve the lowest achievable emission rates as such terms are defined under the new source review provisions of the federal Clean Air Act. Any such modifications would likely result in substantial additional capital expenditures.

 

The Company may incur additional costs or delays in the construction and operation of new plants, improvements to existing plants, or the implementation of environmental control equipment at existing plants and may not be able to recover their investment or complete the project.

 

The Company is in the process of constructing new generation facilities, improving its existing facilities and adding environmental controls to its existing facilities. The construction, expansion, modification and refurbishment of power generation facilities involve many additional risks, including:

 

 

Any of these risks could cause NRG’s financial returns on new investments to be lower than expected, or could cause the Company to operate below expected capacity or availability levels, which could result in lost revenues, increased expenses, higher maintenance costs and penalties. Insurance is maintained to protect against these risks, warranties are generally obtained for limited periods relating to the construction of each project and its equipment in varying degrees, and contractors and equipment suppliers are obligated to meet certain performance levels. The insurance, warranties or performance guarantees, however, may not be adequate to cover increased expenses. As a result, a project may cost more than projected and may be unable to fund principal and interest payments under its construction financing obligations, if any. A default under such a financing obligation could result in losing the Company’s interest in a power generation facility.

 

If the Company is unable to complete the development or construction of a facility or environmental control, or decides to delay or cancel such project, it may not be able to recover its investment in that facility or environmental control. Furthermore, if construction projects are not completed according to specification, the Company may incur liabilities and suffer reduced plant efficiency, higher operating costs and reduced net income.

 

The Company’s RepoweringNRG program is subject to financing risks that could adversely impact NRG’s financial performance.

 

While NRG currently intends to develop and finance the more capital intensive, solid fuel-fired projects included in the Repowering NRG program on a non-recourse or limited recourse basis through separate project financed entities, and intends to seek additional investments in most of these projects from third parties, NRG

anticipates that it will need to make significant equity investments in these projects. NRG may also decide to develop and finance some of the projects, such as smaller gas-fired and renewable projects, using corporate financial resources rather than non-recourse debt, which could subject NRG to significant capital expenditure requirements and to risks inherent in the development and construction of new generation facilities. In addition to providing some or all of the equity required to develop and build the proposed projects, NRG’s ability to finance these projects on a non-recourse basis is contingent upon a number of factors, including the terms of the EPC contracts, construction costs, PPAs and fuel procurement contracts, capital markets conditions, the availability of tax credits and other government incentives for certain new technologies. To the extent NRG is not able to obtain non-recourse financing for any project or should the credit rating agencies attribute a material amount of the project finance debt to NRG’s credit, the financing of the Repowering NRG projects could have a negative impact on the credit ratings of NRG.

 

As part of the Repowering NRG program, NRG may also choose to undertake the repowering, refurbishment or upgrade of current facilities based on the Company’s assessment that such activity will provide adequate financial returns. Such projects often require several years of development and capital expenditures before commencement of commercial operations, and key assumptions underpinning a decision to make such an investment may prove incorrect, including assumptions regarding construction costs, timing, available financing and future fuel and power prices.

 

Supplier and/or customer concentration at certain of NRG’s facilities may expose the Company to significant financial credit or performance risks.

 

NRG often relies on a single contracted supplier or a small number of suppliers for the provision of fuel, transportation of fuel and other services required for the operation of certain of its facilities. If these suppliers cannot perform, the Company utilizes the marketplace to provide these services. There can be no assurance that the marketplace can provide these services as, when and where required.

 

At times, NRG relies on a single customer or a few customers to purchase all or a significant portion of a facility’s output, in some cases under long-term agreements that account for a substantial percentage of the anticipated revenue from a given facility. The Company has also hedged a portion of its exposure to power price fluctuations through forward fixed price power sales and natural gas price swap agreements. Counterparties to these agreements may breach or may be unable to perform their obligations. NRG may not be able to enter into replacement agreements on terms as favorable as its existing agreements, or at all. If the Company was unable to enter into replacement PPA’s, the Company would sell its plants’ power at market prices. If the Company is unable to enter into replacement fuel or fuel transportation purchase agreements, NRG would seek to purchase the Company’s fuel requirements at market prices, exposing the Company to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price.

 

The failure of any supplier or customer to fulfill its contractual obligations to NRG could have a material adverse effect on the Company’s financial results. Consequently, the financial performance of the Company’s facilities is dependent on the credit quality of, and continued performance by, suppliers and customers.

 

NRG relies on power transmission facilities that it does not own or control and that are subject to transmission constraints within a number of the Company’s core regions. If these facilities fail to provide NRG with adequate transmission capacity, the Company may be restricted in its ability to deliver wholesale electric power to its customers and the Company may either incur additional costs or forego revenues. Conversely, improvements to certain transmission systems could also reduce revenues.

 

NRG depends on transmission facilities owned and operated by others to deliver the wholesale power it sells from the Company’s power generation plants to its customers. If transmission is disrupted, or if the transmission capacity infrastructure is inadequate, NRG’s ability to sell and deliver wholesale power may be adversely impacted. If a region’s power transmission infrastructure is inadequate, the Company’s recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure. The Company cannot also predict whether transmission facilities will be expanded in specific markets to accommodate competitive access to those markets.

In addition, in certain of the markets in which NRG operates, energy transmission congestion may occur and the Company may be deemed responsible for congestion costs if it schedules delivery of power between congestion zones during times when congestion occurs between the zones. If NRG were liable for such congestion costs, the Company’s financial results could be adversely affected.

 

In the CAISO, NYISO and NE-ISO markets, the Company has a significant amount of generation located in load pockets, making that generation valuable, particularly with respect to maintaining the reliability of the transmission grid. Expansion of transmission systems to reduce or eliminate these load pockets could negatively impact the value or profitability of our existing facilities in these areas.

 

Because NRG owns less than a majority of some of its project investments, the Company cannot exercise complete control over their operations.

 

NRG has limited control over the operation of some project investments and joint ventures because the Company’s investments are in projects where it beneficially owns less than a majority of the ownership interests. NRG seeks to exert a degree of influence with respect to the management and operation of projects in which it owns less than a majority of the ownership interests by negotiating to obtain positions on management committees or to receive certain limited governance rights, such as rights to veto significant actions. However, the Company may not always succeed in such negotiations. NRG may be dependent on its co-venturers to operate such projects. The Company’s co-venturers may not have the level of experience, technical expertise, human resources management and other attributes necessary to operate these projects optimally. The approval of co-venturers also may be required for NRG to receive distributions of funds from projects or to transfer the Company’s interest in projects.

 

Future acquisition activities may have adverse effects.

 

NRG may seek to acquire additional companies or assets in the Company’s industry. The acquisition of power generation companies and assets is subject to substantial risks, including the failure to identify material problems during due diligence, the risk of over-paying for assets and the inability to arrange financing for an acquisition as may be required or desired. Further, the integration and consolidation of acquisitions requires substantial human, financial and other resources and, ultimately, the Company’s acquisitions may not be successfully integrated. There can be no assurances that any future acquisitions will perform as expected or that the returns from such acquisitions will support the indebtedness incurred to acquire them or the capital expenditures needed to develop them.

 

NRG’s business is subject to substantial governmental regulation and may be adversely affected by legislative or regulatory changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.

 

NRG’s business is subject to extensive foreign, and US federal, state and local laws and regulation. Compliance with the requirements under these various regulatory regimes may cause the Company to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines, and/or civil or criminal liability.

 

Public utilities under the FPA are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. All of NRG’s non-qualifying facility generating companies and power marketing affiliates in the US make sales of electricity in interstate commerce and are public utilities for purposes of the FPA. The FERC has granted each of NRG’s generating and power marketing companies the authority to sell electricity at market-based rates. The FERC’s orders that grant NRG’s generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that NRG can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, NRG’s market-based sales are subject to certain market behavior rules, and if any of NRG’s generating and power marketing companies were deemed to have violated one of those rules, they are subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority. If NRG’s generating and power marketing companies were to lose their market-based rate authority, such companies would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become

subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates NRG charges for power from its facilities.

 

NRG is also affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules that occur in the existing ISOs. The ISOs that oversee most of the wholesale power markets impose, and in the future may continue to impose, mitigation, including price limitations, offer caps, and other mechanisms to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of NRG’s generation facilities that sell energy and capacity into the wholesale power markets.

 

The regulatory environment applicable to the electric power industry has undergone substantial changes over the past several years as a result of restructuring initiatives at both the state and federal levels. These changes are ongoing and the Company cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on NRG’s business. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism, as well as proposals to re-regulate the markets or require divestiture by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process. If competitive restructuring of the electric power markets is reversed, discontinued, or delayed, our business prospects and financial results could be negatively impacted.

 

NRG’s ownership interest in a nuclear power facility subjects the Company to regulations, costs and liabilities uniquely associated with these types of facilities.

 

Under the Atomic Energy Act of 1954, as amended, or AEA, operation of STP, of which NRG indirectly owns a 44.0% interest, is subject to regulation by the NRC. Such regulation includes licensing, inspection, enforcement, testing, evaluation and modification of all aspects of nuclear reactor power plant design and operation, environmental and safety performance, technical and financial qualifications, decommissioning funding assurance and transfer and foreign ownership restrictions. NRG’s 44% share of the output of STP represents approximately 1,175 MW of generation capacity.

 

There are unique risks to owning and operating a nuclear power facility. These include liabilities related to the handling, treatment, storage, disposal, transport, release and use of radioactive materials, particularly with respect to spent nuclear fuel, and uncertainties regarding the ultimate, and potential exposure to, technical and financial risks associated with modifying or decommissioning a nuclear facility. The NRC could require the shutdown of the plant for safety reasons or refuse to permit restart of the unit after unplanned or planned outages. New or amended NRC safety and regulatory requirements may give rise to additional operation and maintenance costs and capital expenditures. STP may be obligated to continue storing spent nuclear fuel if the Department of Energy continues to fail to meet its contractual obligations to STP made pursuant to the US Nuclear Waste Policy Act of 1982 to accept and dispose of STP’s spent nuclear fuel. See also “Environmental Matters — US Federal Environmental Initiatives — Nuclear Waste” in Item 1 for further discussion. Costs associated with these risks could be substantial and have a material adverse effect on NRG’s results of operations, financial condition or cash flow. In addition, to the extent that all or a part of STP is required by the NRC to permanently or temporarily shut down or modify its operations, or is otherwise subject to a forced outage, NRG may incur additional costs to the extent it is obligated to provide power from more expensive alternative sources — either NRG’s own plants, third party generators or the ERCOT — to cover the Company’s then existing forward sale obligations. Such shutdown or modification could also lead to substantial costs related to the storage and disposal of radioactive materials and spent nuclear fuel.

 

NRG and the other owners of STP maintain nuclear property and nuclear liability insurance coverage as required by law. The Price-Anderson Act, as amended by the Energy Policy Act of 2005, requires owners of nuclear power plants in the US to be collectively responsible for retrospective secondary insurance premiums for liability to the public arising from nuclear incidents resulting in claims in excess of the required primary insurance coverage amount of $300 million per reactor. The Price-Anderson Act only covers nuclear liability associated with any accident in the course of operation of the nuclear reactor, transportation of nuclear fuel to the reactor site, in the storage of nuclear fuel and waste at the reactor site and the transportation of the spent nuclear fuel and nuclear waste

from the nuclear reactor. All other non-nuclear liabilities are not covered. Any substantial retrospective premiums imposed under the Price-Anderson Act or losses not covered by insurance could have a material adverse effect on NRG’s financial condition, results of operations or cash flows.

 

NRG is subject to environmental laws and regulations that impose extensive and increasingly stringent requirements on the Company’s ongoing operations, as well as potentially substantial liabilities arising out of environmental contamination. These environmental requirements and liabilities could adversely impact NRG’s results of operations, financial condition and cash flows.

 

NRG’s business is subject to the environmental laws and regulations of foreign, federal, state and local authorities. The Company must comply with numerous environmental laws and regulations and obtain numerous governmental permits and approvals to operate the Company’s plants. Should NRG fail to comply with any environmental requirements that apply to its operations, the Company could be subject to administrative, civil and/or criminal liability and fines, and regulatory agencies could take other actions seeking to curtail the Company’s operations. In addition, when new requirements take effect or when existing environmental requirements are revised, reinterpreted or subject to changing enforcement policies, NRG’s business, results of operations, financial condition and cash flows could be adversely affected.

 

Environmental laws and regulations have generally become more stringent over time, and the Company expects this trend to continue. Regulations currently under revision by USEPA, including CAIR, MACT, standards to control Mercury and the 316 (b) rule to mitigate impact by once through cooling, could result in tighter standards or reduced compliance flexibility. While the NRG fleet employs advanced controls and utilizes industry’s best practices, new regulations to address tightened National Ambient Air Quality Standards for Ozone and PM 2.5 or new rules to further restrict ash handling at coal-fired power plants could also further restrict plant operations.

 

Furthermore, certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. The Company is generally responsible for all liabilities associated with the environmental condition of its power generation plants, including any soil or groundwater contamination that may be present, regardless of when the liabilities arose and whether the liabilities are known or unknown, or arose from the activities of predecessors or third parties.

 

Policies at the national, regional and state levels to regulate GHG emissions could adversely impact NRG’s result of operations, financial condition and cash flows.

 

At the national level and at various regional and state levels, policies are under development to regulate GHG emissions, thereby effectively putting a cost on such emissions in order to create financial incentive to reduce them. In addition the EPA is giving consideration to control of CO ₂ emissions from power plants via existing sections of the CAA. Since power plants, particularly coal-fired plants, are a significant source of GHG emissions both in the US and globally, it is almost certain that GHG regulatory actions will encompass power plants as well as other GHG emitting stationary sources. In 2008, in the course of producing approximately 80 million MWh of electricity, NRG’s power plants emitted 68 million tonnes of CO ₂ , of which 61 million tonnes were emitted in the US, 4 million tonnes in Germany and 3 million tonnes in Australia.

 

Federal, state or regional regulation of GHG emissions could have a material impact on the Company’s financial performance. The actual impact on the Company’s financial performance will depend on a number of factors, including the overall level of GHG reductions required under any such regulations, the price and availability of offsets, and the extent to which NRG would be entitled to receive CO ₂ emissions allowances without having to purchase them in an auction or on the open market.

 

Of the approximately 61 million tonnes of CO ₂ emitted by NRG in the US in 2008, approximately 12 million tonnes were emitted from the Company’s generating units in Connecticut, Delaware, Maryland, Massachusetts, and New York that are subject to RGGI starting in 2009. The impact of RGGI on power prices (and thus on the Company’s financial performance), indirectly through generators seeking to pass through the cost of their CO ₂ emissions, cannot be predicted. However, NRG believes that due to the absence of CO ₂ allowance allocations under RGGI, the direct financial impact on NRG is likely to be negative as the Company will incur costs in the course of securing the necessary allowances and offsets at auction and in the market.

NRG’s business, financial condition and results of operations could be adversely impacted by strikes or work stoppages by its unionized employees or inability to replace employees as they retire.

 

As of December 31, 2008, approximately 66% of NRG’s employees at its US generation plants were covered by collective bargaining agreements. In the event that the Company’s union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or disruption, NRG would be responsible for procuring replacement labor or the Company could experience reduced power generation or outages. NRG’s ability to procure such labor is uncertain. Strikes, work stoppages or the inability to negotiate future collective bargaining agreements on favorable terms could have a material adverse effect on the Company’s business, financial condition, results of operations and cash flow. In addition, a number of our employees at our plants are close to retirement. Our inability to replace those workers could create potential knowledge and expertise gaps as those workers retire.

 

Changes in technology may impair the value of NRG’s power plants.

 

Research and development activities are ongoing to provide alternative and more efficient technologies to produce power, including fuel cells, “clean” coal and coal gasification, micro-turbines, photovoltaic (solar) cells and improvements in traditional technologies and equipment, such as more efficient gas turbines. Advances in these or other technologies could reduce the costs of power production to a level below what the Company has currently forecasted, which could adversely affect its cash flow, results of operations or competitive position.

 

Acts of terrorism could have a material adverse effect on NRG’s financial condition, results of operations and cash flows.

 

NRG’s generation facilities and the facilities of third parties on which they rely may be targets of terrorist activities, as well as events occurring in response to or in connection with them, that could cause environmental repercussions and/or result in full or partial disruption of the facilities ability to generate, transmit, transport or distribute electricity or natural gas. Strategic targets, such as energy-related facilities, may be at greater risk of future terrorist activities than other domestic targets. Any such environmental repercussions or disruption could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on the Company’s financial condition, results of operations and cash flow.

 

NRG’s international investments are subject to additional risks that its US investments do not have.

 

NRG has investments in power projects in Australia and Germany. International investments are subject to risks and uncertainties relating to the political, social and economic structures of the countries in which it invests. The likelihood of such occurrences and their overall effect upon NRG may vary greatly from country to country and are not predictable. Risks specifically related to our investments in international projects may include:

 

 

NRG’s level of indebtedness could adversely affect its ability to raise additional capital to fund its operations, or return capital to stockholders. It could also expose it to the risk of increased interest rates and limit its ability to react to changes in the economy or its industry.

 

NRG’s substantial debt could have important consequences, including:

 

 

 

The indentures for NRG’s notes and senior secured credit facility contain financial and other restrictive covenants that may limit the Company’s ability to return capital to stockholders or otherwise engage in activities that may be in its long-term best interests. NRG’s failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of all of the Company’s indebtedness.

 

In addition, NRG’s ability to arrange financing, either at the corporate level or at a non-recourse project-level subsidiary, and the costs of such capital, are dependent on numerous factors, including:

 

 

NRG may not be successful in obtaining additional capital for these or other reasons. The failure to obtain additional capital from time to time may have a material adverse effect on its business and operations.

 

Goodwill and/or other intangible assets not subject to amortization that NRG has recorded in connection with its acquisitions are subject to mandatory annual impairment evaluations and as a result, the Company could be required to write off some or all of this goodwill and other intangible assets, which may adversely affect the Company’s financial condition and results of operations.

 

In accordance with the Financial Accounting Standards Board, or FASB, Accounting Standard Number 142, Goodwill and Other Intangible Assets , or SFAS 142, goodwill is not amortized but is reviewed annually or more frequently for impairment and other intangibles are also reviewed at least annually or more frequently, if certain conditions exist, and may be amortized. Any reduction in or impairment of the value of goodwill or other intangible assets will result in a charge against earnings which could materially adversely affect NRG’s reported results of operations and financial position in future periods.

 

Exelon Corporation’s unsolicited acquisition proposal and tender offer for all the Company’s outstanding common stock is disruptive to the Company’s management and business and creates uncertainty that may adversely affect our business.

 

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, referred to as the Exelon tender offer, for all of the Company’s outstanding common stock. 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. On January 30, 2009 Exelon also announced a proposed slate of nine nominees for election to NRG’s Board of Directors at the 2009 Annual Meeting of Stockholders, together with a proposal to increase the number of NRG directors from 12 to 19 with two vacancies, referred to as the Exelon proxy contest. The review and consideration of the Exelon tender offer and proxy contest, have been, and may continue to be, a significant distraction for our management and employees and have required, and may continue to require, the expenditure of significant time and resources by the Company. Exelon’s tender offer and proxy contest have also created uncertainty for the Company’s employees and this uncertainty may adversely affect the Company’s ability to retain key employees and to hire new talent. Exelon’s tender offer and proxy contest may also create uncertainty for current and potential business partners, which may cause them to terminate, or not to renew or enter into, arrangements with the Company. In addition, if the Exelon nominees are elected to NRG’s Board of Directors, the ability of management to work effectively and efficiently with NRG’s Board of Directors with respect to the day to day operations and development of the Company may be restricted, and as a result, may harm the Company’s business. Furthermore, the Company and its Board of Directors are defendants in three purported stockholder class action complaints relating to the Exelon proposal as more fully described in Part I, Item 3 “Legal Proceedings” of this Annual Report on Form 10-K. These lawsuits or any future similar or related lawsuits may become time consuming and expensive. These consequences, alone or in combination, may harm the Company’s business.

 

Exelon Corporation’s proxy contest, board expansion and director nominations could result in a Change of Control, as that term is used in the Company’s Senior Credit Facility and Senior Notes, which may adversely affect our business.

 

A default under the Company’s Senior Credit Facility and a mandatory change in control offer under the Senior Notes may be triggered if the Exelon nominees compose a majority of NRG’s Board of Directors at any time. A Change of Control under the Company’s Senior Credit Facility and Senior Notes could occur if the two vacancies on NRG’s Board of Directors (created only if the Company’s shareholders approve Exelon’s proposal to the expand NRG’s Board of Directors to 19 members) are not filled by directors nominated by the current NRG Board. A Change of Control may also be triggered by other future events where the resulting composition of NRG’s Board of Directors consists of a majority of Exelon nominated directors, such as the retirement or death of any non-Exelon nominated Board member. If a Change of Control is triggered under the Senior Credit Facility and Senior Notes this could have a material and significant impact on the Company’s business.

Cautionary Statement Regarding Forward Looking Information

 

This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or Securities Act, and Section 21E of the Exchange Act. The words “believes”, “projects”, “anticipates”, “plans”, “expects”, “intends”, “estimates” and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause NRG Energy, Inc.’s actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Risks Related to NRG in Item 1A of this report and the following:

 

 

Forward-looking statements speak only as of the date they were made, and NRG Energy, Inc. undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause NRG’s actual results to differ materially from those contemplated in any forward-looking statements included in this Annual Report on Form 10-K should not be construed as exhaustive.