NRG Energy (NRG)

 

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(b) of the Act:

 

 

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 Ruler 12b-2 of the Exchange Act. (Check one):

 

 

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 $9,869,468,545 based on the closing sale price of $41.57 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 2008 Annual Meeting of Stockholders to be held on May 14, 2008

 

 

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:

 

 

 

 

 

 

 

General

 

NRG Energy, Inc., or NRG or the Company, is a wholesale power generation company with a significant presence in major competitive power markets in the United States. NRG is engaged in the ownership, development, construction and operation of power generation facilities, the transacting in and trading of fuel and transportation services, and the trading of energy, capacity and related products in the United States and select international markets. As of December 31, 2007, NRG had a total global portfolio of 191 active operating generation units at 49 power generation plants, with an aggregate generation capacity of approximately 24,115 MW, and approximately 740 MW under construction which includes partners’ interests. Within the United States, NRG has one of the largest and most diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with approximately 22,880 MW of generation capacity in 175 active generating units at 43 plants. These power generation facilities are primarily located in Texas (approximately 10,805 MW), the Northeast (approximately 6,980 MW), South Central (approximately 2,850 MW), and West (approximately 2,130 MW) regions of the United States, with approximately 115 MW of additional generation capacity from the Company’s thermal assets. NRG’s principal domestic power plants consist of a mix of natural gas-, coal-, oil-fired and nuclear facilities, representing approximately 46%, 33%, 16% and 5% of the Company’s total domestic generation capacity, respectively. In addition, 15% of NRG’s domestic generating facilities have dual or multiple fuel capacity, which allows plants to dispatch with the lowest cost fuel option. NRG’s domestic generation facilities consist of baseload, intermediate and peaking power generation facilities, the ranking of which is referred to as Merit Order, and include thermal energy production plants. The sale of capacity and power from baseload generation facilities accounts for the majority of the Company’s revenues and provides a stable source of cash flow. In addition, NRG’s generation portfolio provides the Company with opportunities to capture additional revenues by selling power during periods of peak demand, offering capacity or similar products to retail electric providers and others, and providing ancillary services to support system reliability.

 

NRG’s Major Initiatives

 

The Company’s strategy is reflected in its five major initiatives, four of which were announced and began implementation in 2006. The fifth, “Focus on ROIC @NRG”, or FORNRG, successfully concluded its third year in 2007. NRG’s five major initiatives, described below, are designed to enhance the Company’s competitive advantages of the opportunities and surmount the challenges faced by the power industry.

 

 

 

 

 

Business Strategy

 

NRG’s strategy is to optimize the value of the Company’s generation assets while using its asset base as a platform for growth and enhanced financial performance which can be sustained and expanded upon in the years to come. NRG plans to maintain and enhance the Company’s position as a leading wholesale power generation company in the United States in a cost-effective and risk-mitigating manner in order to serve the bulk power requirements of NRG’s existing customer base and other entities that offer load or otherwise consume wholesale electricity products and services in bulk. NRG’s strategy includes the following principles:

 

Increase value from existing assets — NRG has a highly diversified portfolio of power generation assets in terms of region, fuel-type and dispatch levels. Through the FORNRG 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 ROIC.

 

Reduce the volatility of the Company’s cash flows through asset-based commodity hedging activities — NRG 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.

 

Pursue additional growth opportunities at existing sites — 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 RepoweringNRG 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. 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.

 

Reduce carbon intensity of portfolio while taking advantage of carbon-driven business opportunities — NRG continues to actively pursue investments in new generating facilities and technologies that will be highly efficient and will employ no and low carbon technologies to limit CO₂ emissions and other air emission. Through the RepoweringNRG and econrg initiatives, NRG is focused on the development of low or no GHG emitting energy generating sources, such as nuclear, wind, ’clean’ coal and gas, and the employment of post-combustion capture technologies, which represent significant commercial opportunities.

 

Maintain financial strength and flexibility — 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. NRG will continue to focus on maintaining operational and financial controls designed to ensure that the Company’s financial position remains strong. At the same time, the Company’s ongoing capital allocation objective includes scheduled repayment of debt based on the amount of cash flow by the Company each year, as well as an annual return of capital to shareholders, targeted at an average rate of 3% of market capitalization, of approximately $250 million to $300 million per year.

 

Pursue strategic acquisitions and divestures — 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 United States, with approximately 22,880 MW of generation capacity in 175 active generating units at 43 plants as of December 31, 2007. 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 U.S. baseload facilities, which consist of approximately 8,700 MW of generation capacity measured as of December 31, 2007, provide the Company with a significant source of stable cash flow, while its intermediate and peaking facilities, with approximately 14,180 MW of generation capacity as of December 31, 2007, 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.

The following chart demonstrates the diversification of NRG’s domestic power generation assets as of December 31, 2007:

 

 

Reliability of future cash flows — NRG has sold forward or otherwise hedged a significant portion of its expected baseload generation capacity through 2013. The Company has the capacity and intent to enter into additional hedges in later years when market conditions are favorable. In addition, as of December 31, 2007, the Company had purchased forward under fixed price contracts (with contractually-specified price escalators) to provide fuel for approximately 59% of its expected baseload coal generation output from 2008 to 2013. 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 2007, approximately 87% 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 ERCOT to generate power nearly 100% 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 with 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. These facilities also are often ideally situated for repowering or the addition of new capacity, because their location and existing infrastructure give them significant advantages over newly developed sites in their regions.

Performance Metrics

 

The following table contains a summary of NRG’s operating revenues by segment for the year ended December 31, 2007 as discussed in Item 15 — Note 17, Segment Reporting, to the Consolidated Financial Statements.

 

 

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 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: — NRG calculates the gross heat rate for the Company’s fossil-fired power plants by dividing the average amount of fuel in BTUs required to generate one kWh of electricity 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, 2007 and 2006:

 

 

 

 

 

Employees

 

As of December 31, 2007, NRG had 3,412 employees, approximately 1,639 of whom were covered by U.S. bargaining agreements. During 2007, 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 United States as set forth in the map below:

 

 

 

 

As of December 31, 2007, the Company’s power generation assets consisted of approximately 10,490 MW of gas-fired; 7,525 MW of coal-fired; 3,690 MW of oil-fired and 1,175 MW of nuclear generating capacity in the United States. In addition, NRG also owns approximately 115 MW of thermal capacity domestically as well as 1,235 MW of power generation capacity overseas. The Company’s North American power generation portfolio by

dispatch level is comprised of approximately 38% baseload, 37% intermediate and 25% of peaking units. NRG uses hedging strategies which may include power and natural gas forward sales contracts to manage the commodity price risk associated with the Company’s generation assets, and are primarily around the Company’s baseload generation assets. In addition, these hedging strategies also provide for stable cash flow and earnings predictability.

 

The following table summarizes NRG’s North American baseload capacity and the corresponding revenues and average natural gas prices resulting from baseload hedge agreements extending beyond December 31, 2007 and through 2013:

 

 

 

 

The following is a discussion of NRG’s generation assets by segment for the year ended December 31, 2007.

 

Texas Region — As of December 31, 2007, NRG’s generation assets in the Texas region consisted of approximately 5,325 MW of baseload generation assets and approximately 5,480 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 uses lignite and coal, and an undivided 44% interest in two nuclear generating units at South Texas Project, or STP, which uses nuclear fuel. Power plants are generally dispatched in order of lowest operating cost and as of December 31, 2007, approximately 72% of the net generation capacity in the ERCOT market was natural gas-fired. In the current natural gas price environment, NRG’s three baseload facilities have

significantly lower operating costs than gas plants. NRG expects these three facilities to operate nearly 100% of the time when available, subject to planned and forced outages.

 

Northeast Region — As of December 31, 2007, NRG generation assets in the Northeast region of the United States consisted of approximately 6,980 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 535 MW of southwest Connecticut generation capacity. As of December 31, 2007, NRG’s generation assets in the Northeast region consisted of approximately 1,870 MW of baseload generation assets and approximately 5,110 MW of intermediate and peaking assets.

 

South Central Region — As of December 31, 2007, NRG generation assets in the South Central region of the United States consisted of approximately 2,405 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 the South Central region consists of its primary asset, Big Cajun II, a coal-fired plant located near Baton Rouge, Louisiana which has approximately 1,490 MW of baseload generation assets and 1,360 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 2025. In addition, the region also operates 445 MW of peaking generation in Rockford, Illinois under the PJM region.

 

West Region — As of December 31, 2007, NRG generation assets in the West region of the United States consisted of approximately 2,130 MW. On January 3, 2007, NRG completed the sale of the Red Bluff and Chowchilla II power plants with a combined generation capacity of approximately 95 MW to an entity controlled by Wayzata Investment Partners LLC. On August 1, 2007, the Company successfully completed and commissioned the repowering of 260 MW of new gas-fired generating capacity at its Long Beach Generating Station.

 

International Region — As of December 31, 2007, NRG had net ownership in approximately 1,235 MW of power generating capacity outside the United States in Australia, Brazil, and Germany. In addition to traditional power generation facilities, NRG also owns equity interests in certain coal mines in Germany. On December 18, 2007, NRG entered into a sale and purchase agreement to sell its 100% interest in Tosli Acquisition B.V., which holds all of NRG’s interest in ITISA, to Brookfield Asset Management Inc. for the purchase price of $288 million, plus the assumption of approximately $60 million in debt. NRG anticipates the completion of the sale transaction during the first half 2008.

 

Thermal — NRG owns thermal and chilled water businesses that generate approximately 1,040 MW thermal equivalents. In addition, NRG’s thermal segment owns certain power plants with approximately 116 MW of power generating capacity located in Delaware and in 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 power purchase agreements 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, the Company hedges a portion of its generation portfolio power using natural gas swaps and other financial instruments.

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. Issues 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, 2007, NRG had purchased forward contracts to provide fuel for approximately 59% of the Company’s requirement from 2008 through 2013. 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 transportation agreements and rail car lease arrangements. The Company purchased approximately 38 million tons of coal in 2007, and is one of the largest coal purchasers in the United States.

 

The following table shows the percentage of the Company’s coal and lignite requirements from 2008 through 2013 that have been purchased forward:

 

 

 

 

As of December 31, 2007, NRG had approximately 7,600 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 through the end of the decade.

 

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 on 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 through the end of the next decade. 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 September, 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 fuel prices have tended to drive seasonal electricity prices. Issues 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 RepoweringNRG initiatives, the Company has organized its project execution process into one centralized group consisting of engineering, procurement and construction, or EPC. This group combines regional engineering functions with corporate project engineering, project management, procurement and construction functions to provide a consistent and standardized execution of the repowering initiative. 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 expects to achieve 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.

 

Environmental Capital Expenditures

 

Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures to be incurred from 2008 through 2012 to meet NRG’s environmental commitments will be between $1.0 billion and $1.4 billion. These capital expenditures, in general, are related to installation of particulate, SO₂, NO_x, and mercury controls to comply with Clean Air Interstate Rule, or CAIR, the Clean Air Mercury Rule, or CAMR, and related state requirements 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. The range reflects alternative strategies available with respect to the Company’s Indian River plant.

 

The following table summarizes the upper end of the estimated range for major environmental capital expenditures for the referenced periods by region:

 

 

NRG plans to reduce the impact of a portion of the above environmental capital expenditures. NRG has the ability to monetize a portion of the Company’s excess allowances over the 2008 through 2012 timeframe and still hold sufficient allowances to operate the fleet with proposed controls through at least 2020. In addition, 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 and the treatment of these expenditures.

Carbon Update

 

There is a growing consensus in the U.S. and globally that GHG emissions are a major cause of global warming. 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, earlier this year, the U.S. Supreme Court found that CO₂, the most common GHG, could be regulated as a pollutant and that the USEPA should regulate CO₂ emissions from mobile sources. Since power plants, particularly coal-fired plants, are a significant source of GHG emissions both in the United States and globally, it is almost certain that GHG regulatory actions will encompass power plants as well as other GHG emitting stationary sources. In 2007, in the course of producing approximately 80 million MWh of electricity, NRG’s power plants emitted 68 million tonnes of CO₂, of which 61 million tonnes were emitted in the United States, 3 million tonnes in Australia and 4 million tonnes in Germany.

 

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 GHG emissions allowances without having to purchase them in an auction or on the open market. For example, the U.S. Senate is currently considering climate change legislation sponsored by Senators Lieberman and Warner. If legislation with the same level of allocations to existing generation resources and emissions reductions as those contained in the current version of the Lieberman-Warner legislation were enacted, NRG expects that the legislation will have a minimal impact on the Company’s financial performance through the next decade. Thereafter, under such legislation, the impact on NRG would depend on the Company’s level of success in developing and deploying low and no carbon technologies being pursued as part of our RepoweringNRG and econrg initiatives. Additionally, NRG’s current contracts with its South Central region’s cooperative customers allows for the recovery of emission-based costs.

 

State and regional initiatives such as the Regional Greenhouse Gas Initiative, or RGGI, in the Northeast, and the Western Climate Initiative, or WCI, are developing market-based programs to counteract climate change. The RGGI states are in the process of promulgating state regulations needed for implementation with six of the ten states issuing drafts for comment. With state legislation and regulation in place, the first regional auction of RGGI allowances needed by power generators could be held as early as the summer of 2008. WCI is in the formative stages of the regional effort. California has enacted Assembly Bill 32 — California Global Warming Solutions Act of 2006, or AB32, which requires the California Air Resources Board to develop a GHG reduction program to reduce emissions to 1990 levels by 2020, a reduction of approximately 25%. This reduction program will be phased in beginning 2012 pursuant to regulations to be adopted by 2011.

 

NRG does not expect that implementation of AB32 in California will 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. However, of the approximately 61 million tonnes of CO₂ emitted by NRG in the United States in 2007, approximately 12 million tonnes were emitted from the Company’s generating units in Connecticut, Delaware, Maryland, Massachusetts and New York that will likely be subject to RGGI 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 CO₂ emissions, cannot be predicted. However, NRG believes that due to the absence of any significant 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.

 

In this regard, the Company has a multifold strategy with respect to climate change and related GHG regulation. First, the Company is seeking to influence 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 be supportive of the research, development, demonstration and deployment of low and no carbon power generation technologies. The Company is carrying out its efforts to influence public policy on its own and as part of two collective efforts. In July 2007, NRG joined the United States Climate Action Partnership, or USCAP, an alliance of major businesses and leading climate and environmental

groups which are calling for federal legislation requiring significant reductions of GHG emissions. Also in January 2007, the Company joined with 46 other global business leaders to support a new initiative, Combating Climate Change, or 3C. This initiative calls for the global business community to take a leadership role in designing the road map to a low carbon society.

 

Second, the Company is actively pursuing investments in new generating facilities and technologies that will be highly efficient and will employ no and low carbon technologies to limit CO₂ emissions and other air emissions through its RepoweringNRG program. The Company anticipates that these investments will result in 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 (gross) STP units 3 and 4 nuclear project in Texas. In addition to the nuclear development project, the Company has other low and no GHG emitting wind, ’clean’ coal and gas projects under active development. The extent to which these projects, and our remaining coal projects under development, impact our overall carbon exposure will depend on our 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 carbon risk associated with our development projects are 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 carbon capture technologies. For example, NRG is working with Powerspan Corp, or Powerspan, to deploy a scaled up demonstration of their ammonium-based ECO₂^tm carbon capture technology at the Company’s W.A. Parish facility in Texas. The captured CO₂ would be either sequestered or used in enhanced oil recovery operations. The Company believes that there may be significant commercial opportunity in participating in such a project.

 

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. In May 2007, the Company joined the Chicago Climate Exchange, a GHG emissions reduction, registry and trading system, as part of the Company’s ongoing program to increase its climate change awareness, track its CO₂ emissions and address climate change proactively.

 

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 GHG 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.

 

FORNRG Update

 

For 2007, NRG attained its previously announced target of $220 million which includes $11 million of one-time benefits. The 2007 results were largely driven by corporate initiatives and improved performance of the generating fleet particularly in the area of generating capacity, heat rate and station service. During 2007, the Company announced the acceleration and planned conclusion of the FORNRG 1.0 program by bringing forward the previously announced 2009 target of $250 million in pre tax income improvements to 2008. During 2008, the Company will launch the next phase of the program under the banner FORNRG 2.0.

 

RepoweringNRG Update

 

In 2006, NRG announced a comprehensive portfolio redevelopment program, referred to as RepoweringNRG, 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 power purchase agreements, or 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 RepoweringNRG 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 RepoweringNRG 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 CO₂ emissions and other air emissions. The Company anticipates that these investments will result in long-term GHG intensity reductions in its generating portfolio.

 

Although NRG believes it is unlikely that the program will be fully implemented as originally proposed, 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 engineering, procurement and construction, or EPC, contracts. In addition, the proposed increase in generation capacity and capital costs resulting from RepoweringNRG 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 RepoweringNRG 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.

 

The following is a summary of repowering projects that have either been completed and are operating, under construction or in certain stages of development. 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

 

Long Beach — On August 1, 2007, the Company successfully completed and commissioned the repowering of 260 MW of new gas-fired generating capacity at its Long Beach Generating Station. This new generation will provide needed support for the summer peak demand to Southern California Edison, or SCE, and California Independent System Operator, or CAISO. This project is backed by a 10-year PPA executed with SCE in November 2006. The total incremental capital cost for the project was approximately $78 million.

 

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 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.

 

NRG will also provide various ongoing services related to construction management, plant operations and maintenance, and use of existing NRG facilities in return for a fixed fee plus reimbursement of the Company’s costs.

 

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 to construct the plant which is expected to be completed in 2009.

 

Sherbino Wind Farm — On February 1, 2008, NRG, through its wholly owned subsidiary, Padoma Wind Power LLC., entered into a fifty percent partnership with BP Alternative Energy North America Inc. to build the first phase of the Sherbino Wind Farm, a 150 MW wind project. The Sherbino I Wind Farm will be located on a more than 9,000 acre mesa with an elevation of approximately 3,000 feet above sea level, approximately 40 miles east of Fort Stockton in Pecos County, Texas. Initial construction of the Sherbino I Wind Farm commenced in November 2007 and will utilize 50 Vestas V90 3 MW wind turbine generators. The project is scheduled to reach commercial operations by the end of 2008 with NRG’s 50 percent ownership providing a net capacity of 75 MW or the equivalent of 25 generators.

Cos Cob — The Company continues to proceed with the repowering project at its Cos Cob site in Connecticut, with the construction of 40 MW of peaking capacity following the receipt of the siting and air permits. The Company anticipates completion and commissioning of the unit in the summer of 2008.

 

Plants under Development

 

STP Units 3 and 4 — On November 30, 2007, the Nuclear Regulatory Commission, or 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. The total rated capacity of the new units, STP units 3 and 4, will equal or exceed 2,700 MW. The acceptance review confirms that the application, the first to be filed with the NRC in 29 years, is technically complete and sufficiently addresses all necessary subject areas. With the COLA accepted or docketed, the NRC begins a comprehensive and detailed review process that includes requests for additional information, site visits, responses from NRG, public hearings, NRC Environmental Impact Statements and NRC Safety Evaluation Reports. The Company expects to achieve commercial operation for Unit 3 approximately 48 months after issuance of the COLA, and commercial operation for Units 4 approximately 12 months thereafter.

 

On October 29, 2007, NRG and the City of San Antonio, acting through the City Public Service Board of San Antonio, or CPS Energy, entered into an 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. The agreement provides for CPS Energy, based on its ownership percentage, to reimburse NRG for a pro rata share of project costs NRG has incurred, and to pay a pro rata share of future development costs.

 

The Company and STPNOC have also signed a project services agreement with Toshiba Corporation, a diversified major Japanese manufacturer. Under this agreement, Toshiba will support NRG in the design, engineering, construction, and procurement of two nuclear reactors. STPNOC and NRG are engaged in continuing negotiations with Toshiba and its potential consortium members about a definitive EPC agreement. In addition, NRG has also reserved for major, long-lead components for the STP expansion projects, including the first reactor pressure vessel.

 

Huntley IGCC — In December 2006, NRG won a conditional award of a power purchase agreement in support of the construction of a 600MW IGCC plant in a competitive bid process with the New York Power Authority, or NYPA. This plant would be built at the Company’s existing Huntley facility. The bid included selling capacity and energy to NYPA under a long-term PPA. As part of the conditional award, NYPA entered into a strategic alliance with NRG to pursue support from federal, state and local programs in order to close the perceived pricing gap between NRG’s proposal and NYPA’s requirements, while preserving the material benefits of NRG’s proposal relating to innovative clean coal power generation, including CO₂ capture and geologic sequestration plans which the State of New York subsequently required as part of the overall award.

 

Since the announcement of the conditional award, NRG has worked with Mitsubishi Heavy Industries, or MHI, as a technology provider for this project. To date the initial engineering, or feasibility study has been completed for the project. The next phase includes front-end engineering design, or FEED. During this phase, NRG will determine specific design requirements and costing for the project, including CO₂ capture. At the same time, NRG and MHI would negotiate the form of an EPC agreement. NRG has also completed its detailed geological assessment of target sequestration sites which indicates that no fatal flaws exist for the long term injection and storage of the captured CO₂. NRG is working with the State of New York to build the legal and regulatory infrastructure for the injection of the CO₂ and the future responsibility for sequestered carbon.

 

With respect to the price gap closure initiative, the Company has identified existing local and state incentives and programs that can effectively close the price gap. It has submitted these initiatives to the State, where analysis against the State’s budget has begun. NRG expects the State to formally respond to the price gap analysis during the first half of 2008. Any remaining price gaps will need to be closed through federal initiatives and the Company has a federal outreach effort in place to address these initiatives in Washington D.C.

The next significant phase of this project, particularly the FEED work, will require monthly spending at a level that could not be a supported without the State formally approving the award. NRG is working with NYPA and the Governor’s staff to secure this award before moving to the next phase of the project.

 

Big Cajun I — NRG is continuing its development efforts to repower the Big Cajun I site with a 207 net MW circulating fluidized bed boiler, or CFB. NRG has signed a memorandum of understanding with potential co-owners for approximately 50% of the plants’ capacity and has also signed term sheets for long-term PPAs for the remaining 50%. In January 2008, the Company received the Title V air permit for the project from the Louisiana Department of Environmental Quality, or LDEQ, however in February 2008, certain environmental advocacy groups initiated a state court proceeding to challenge of the LDEQ’s decision to issue the air permit and stay the effectiveness of the air permit. NRG believes that claims of the environmental advocacy groups are without merit, and NRG plans to intervene in the state court proceedings. Subject to the favorable resolution of the state court proceedings, the project timeline anticipates an engineering and construction start date in late 2008.

 

Connecticut Peakers — In 2007, the Connecticut legislature passed a law that required state utilities, and permitted others, to submit plans for new peaking generation facilities in Connecticut subject to a regulated long-term contract. In the fall of 2007, NRG and United Illuminating Company, or UI, a wholly-owned subsidiary of UIL Holding Corporation, announced a joint venture to respond to this procurement process. NRG and UI subsequently formed GenConn Energy LLC as their joint venture vehicle and submitted a joint qualification package, as required, on February 1, 2008 with the Department of Public Utility Control, or DPUC. UI and NRG are evaluating the optimal combination of project size and locations that might be offered into their proposal. Binding bids are due March 3, 2008, with a final decision anticipated by June 2008.

 

econrg Update

 

econrg is a complementary program to RepoweringNRG. econrg seeks to reduce the Company’s carbon intensity through the implementation of low and no carbon repowering projects and through the investment in and demonstration of carbon capture and other environmentally advanced technologies. econrg is also focused on increasing environmental awareness, the advocacy of sound environmental policy and reducing the environmental footprint of the Company, its assets and its employees. The following is a summary of the Company’s econrg projects.

 

Commercial Scale Carbon Capture and Sequestration Demonstration

 

On November 2, 2007, NRG signed a memorandum of understanding with Powerspan Corp., or Powerspan, to jointly design, construct, and operate a demonstration facility that will be among the largest carbon capture and sequestration projects in the world and may be the first to achieve commercial scale from an existing coal-fueled power plant. The project will be constructed at NRG’s W.A. Parish plant near Sugar Land, Texas, and is designed to capture and sequester up to 90% of the carbon dioxide from flue gas equal in quantity to that from a 125 MW unit using Powerspan’s proprietary ECO₂^tm technology, a post-combustion, regenerative process which uses an ammonia-based solution to capture CO₂ from the flue gas and release it in a form that is ready for safe transportation and permanent geological storage. The CO₂ from the process would either be sequestered or sold for use in enhanced oil recovery projects. The project, which is expected to be operational in 2012, will be funded by NRG, potential partners and federal and state grants.

 

Plasma Gasification Technology

 

On April 3, 2007, NRG purchased approximately 2.2 million shares at CAD$2.25 per share for a 6% interest in Alter Nrg Corporation, a Canadian company that provides alternative energy solutions using plasma gasification, a process that converts carbon-containing materials into synthetic gas. As part of the transaction NRG has been granted an exclusive license to use Alter Nrg Corporation’s plasma torch technology to (i) gasify fossil fuel and biomass in power projects in the United States, and (ii) develop other gasification projects in the vicinity of existing NRG plants. In January 2008, the Company received a qualified approval from the Massachusetts Department of Environmental Protection to convert the Somerset, MA facility to a coal and biomass gasification power facility.

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.

 

Operating Strategy

 

The Company’s business in Texas is comprised of two sets of assets: a set of three large solid-fuel baseload plants and a set of gas-fired plants located in and around Houston. 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/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 tailored to our 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:

 

 

 

 

Generation Facilities

 

As of December 31, 2007, NRG’s generation facilities in Texas consisted of approximately 10,805 MW of generation capacity. The following table describes NRG’s electric power generation plants and generation capacity as of December 31, 2007:

 

 

 

 

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 United States 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 2,460 MW as of December 31, 2007. Two of these units are 645/650 MW steam units that were placed in commercial service in December 1977 and December 1978, respectively. The other two units are 565 MW and 600 MW steam units that were placed in commercial service in June 1980 and December 1982, respectively. All four units are serviced by two competing railroads that diversify NRG’s coal transportation options at competitive prices. 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 SO₂ 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, 2007. 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 SO₂ 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 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 United States 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, 2007, STP had a zero percent forced outage rate and a 97% 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 South Texas Project Nuclear Operating Company, or 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 fastest growing power markets. It represents approximately 85% of the demand for power in Texas and covers the whole 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 2.5%, compared to a compound annual rate of growth of 2.1% in the United States for the same period. For 2007, hourly demand ranged from a low of 21,790 MW to a high of 62,188 MW. ERCOT has limited interconnections compared to other markets in the United States — 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 experienced significant construction of new generation plants, with over 29,000 MW of new generation capacity added to the market since 1996. As of December 31, 2007, aggregate net generation capacity of approximately 76,800 MW existed in the ERCOT market, of which 71.7% was natural gas-fired. Approximately 20,600 MW, or 26.9%, was lower marginal cost generation capacity such as coal, lignite and nuclear plants. NRG’s coal and nuclear fuel baseload plants represent approximately 5,325 MW gross, or 25.9%, of the total solid fuel baseload net generation capacity in the ERCOT market. ERCOT has established a target equilibrium reserve margin level of approximately 12.5%. The reserve margin for 2007 was 14.6% forecast to drop to 13.1% for 2008 per ERCOT’s latest Capacity Demand and Reserve Report. With the exception of wind generation units, there has been very little generation that has come online since 2004, and ERCOT projects reserve margins to decrease in

2009 primarily due to load growth. Several new projects have been announced or are under construction for 2010 and beyond, and there are currently plans being considered by the 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 ERCOT administers. An October 1, 2005 “Report on Existing and Potential Electric System Constraints and Needs” found that natural gas-fired power plants set the market price of power more than 90% of the time in the ERCOT market. 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.

 

The ERCOT market operates under the reliability standards set by the North American Electric Reliability Council, or NERC. 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. 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 ERCOT does not procure power on behalf of its members other than to maintain the reliable operations of the transmission system. 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 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 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 expected to take effect in December 2008. 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 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 United States 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, Southwest 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 seeks to enhance the value of these sites primarily through the advocacy of capacity market reforms that better reflect their locational value. Over the past year, the Company has benefited from the introduction of more robust capacity market reforms in both the New England Power Pool, or NEPOOL, and PJM. The Locational Forward Reserve Markets, or LFRM, in the NEPOOL, was effective October 1, 2006, and the transition capacity payments were effective December 1, 2006 with an initial price of $3.05/kw month. In all three 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. These relatively new markets serve as a prelude to the full implementation of the Forward Capacity Market, or FCM, which begins June 1, 2010, and for which the first auction was conducted in February 2008. PJM’s reliability pricing model, or RPM, was effective June 1, 2007 and the Company has participated in auctions providing capacity price certainty through May 2011.

 

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 2007, Middletown and Montville were covered by an RMR agreement. Unless terminated earlier, these agreements will terminate on June 1, 2010 which coincides with the commencement of the FCM in NEPOOL. On July 16, 2007, FERC conditionally accepted, subject to refund, the Company’s RMR filing for its Norwalk plant. This RMR was retroactive to June 19, 2007, which coincides with the FERC decision to eliminate PUSH bidding. The Company is engaged in settlement discussions with FERC to determine the actual value of the RMR payment this plant should receive. In the recently-concluded FCM auction for delivery year 2010/2011, the Company sought to de-list Norwalk’s units 1 and 2. ISO-NE declined to accept that de-list bid on the grounds these units were needed for reliability. Norwalk will likely operate pursuant to an RMR agreement after June 1, 2010.

 

Generation Facilities

 

As of December 31, 2007, NRG’s generation facilities in the Northeast region consisted of approximately 6,980 MW of generation capacity, including assets located in transmission constrained areas, such as New York City — 1,415 MW, and Southwest Connecticut — 535 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 500 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 15 MW and is activated when ConEd 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 the spring of 2006, the plant completed changes to switch from eastern bituminous coal to low sulfur PRB coal in order to comply with various federal and state emissions standards, as well as the New York Department of Environmental Conservation, or NYSDEC, settlement referred to in the following paragraph.

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. NRG retired Units 65 and 66 effective June 3, 2007 pursuant to a settlement agreement reached with NYSDEC in January 2005. Per that agreement, NRG will reduce NO_x and SO₂ emissions from the Company’s Huntley and Dunkirk plants through 2013 in the aggregate by over 8,090 lbs and 8,690 lbs, respectively. A large portion of these reductions will be achieved through the use of low sulfur PRB coal and through installation of back end control facilities referred to as baghouses. Construction of the back end control facilities commenced in 2007 and is anticipated to be completed in fall of 2008 for the Huntley facility and fall of 2009 for the Dunkirk facility.

 

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 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. Units 1, 2 and 3 combust 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 DNREC, NRG agreed to operate the units in a manner that would limit the emissions of NO_x, SO₂ 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 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, and by $1,000/MWh energy market price caps that are in place in all three Northeast ISOs.

 

SOUTH CENTRAL

 

As of December 31, 2007, NRG owned approximately 2,850 MW of generating capacity in the South Central region of the United States. The region lacks a regional transmission organization or ISO and, therefore, remains a bilateral market, making it less efficient than a region with an ISO-administered energy market using large scale economic dispatch, such as the Northeast region. 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

 

NRG’s South Central region seeks to capitalize on three factors: (1) its position as a significant coal-fired generator in a market that is highly dependent on natural gas for power generation, (2) its long-term contractual and

historical service relationship with eleven rural cooperatives around Louisiana, and (3) its ability to make incremental wholesale energy sales during periods when its coal-fired capacity exceeds the cooperative contract requirements. The South Central region works with its cooperative customers to expand their and the Company’s customer bases on terms advantageous to all parties. The Company also works within the confines of the Entergy Transmission System to obtain paths for these 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, 2007 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 as of December 31, 2007, and generation capacity per unit of 580 MW, 575 MW and 575 MW, respectively. 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-NO_x burners and overfire air systems. The generators on Units 1 and 3 have been rewound, and the turbine controls on these units have been replaced with a modern digital control system. Unit 2 is scheduled for a generator rewind and turbine controls replacement in future years. Additionally, the turbine high and intermediate pressure steam path on Unit 3 was replaced with a high-efficiency design. Units 1 and 2 are scheduled for similar upgrades in future years. These improvements are expected to cost approximately $28 million. As part of future CAIR and CAMR emission reductions, work is being finalized in the evaluation of installation of new environmental equipment and/or participation in Cap and Trade as allowed in Louisiana’s implementation plan.

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, 2007, 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, and Southwestern Electric Power Company, which collectively comprise an additional 13% 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 typically employs its own gas-fired assets, or alternatively 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, 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 been successful in negotiating contract modifications with several of the region’s long-term cooperative customers, which has prevented the addition of large industrial or municipal loads at the 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. On March 31, 2006, NRG purchased Dynegy Inc’s 50% ownership interest in WCP and became the sole owner of the WCP assets. On January 3, 2007, NRG sold the Red Bluff and the Chowchilla II power plants to Wayzata Investment Partners LLC.

 

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, and the preservation of the commercial value of the underlying real estate. There are three principal components to this strategy: (1) responding to expected market demand, initially in load serving entity RFPs and eventually into a capacity market, and (2) using existing emission allowances to permit new, more efficient generating units at existing sites or siting plants at less valuable property 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 Resource Adequacy, or RA, capacity and consequently the RMR contract with the CAISO on the Encina units has been terminated effective December 31, 2007. CAISO and Cabrillo Power I, LLC, Encina’s owner, entered into dual fuel and black start agreements to supplement the availability obligations to the CAISO provided for under the tolling agreements. The El Segundo Station has sold all energy and capacity, 670 MW, in the aggregate, to a load-serving entity through April 30, 2008, on a tolling basis, and recovers its operating costs plus a capacity payment. For calendar year 2008, the El Segundo station has entered into Resource Adequacy, or RA, contracts with multiple load-serving entities or power marketers, and a tolling agreement with a power marketer for the period May 1, 2008 through December 31, 2008, covering 387 MW of the available 670 MW. Cabrillo II sold 28 MW of RA capacity for 2008 and 88 MW of RA capacity from January 1, 2009 through November 30, 2013. To the extent not covered by an RA agreement, Cabrillo II’s cost of operations including a

return on investment is covered by an RMR agreement that extends through December 31, 2008. It is expected that Cabrillo II’s RMR status will be renewed in 2009.

 

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.

 

Generation Facilities

 

NRG’s power generation assets in the West region as of December 31, 2007 are summarized in the table below:

 

 

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 primarily use natural gas but also maintain dual fuel capability for use only during gas supply force majeure conditions. Also located at the Encina Station is a combustion turbine that provides peaking 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. Units 1, 2 and 3 are projected to be retired after 2010. Low NO_x burner modifications and SCR equipment have been installed on Units 1, 2, 3, 4 and 5.

 

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 new gas-fired generating capacity at its Long Beach Generating Station. This new generation provides needed support for the summer peak demand to Southern California Edison, or SCE, and California Independent System Operator systems. This project is backed by a 10-year PPA executed with SCE in November 2006. Total capital spending for the project was approximately $78 million.

 

Cabrillo II — Cabrillo II consists of 12 combustion turbines located on 4 sites throughout San Diego county with an aggregate generating capacity of 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

 

NRG’s assets in the West region primarily consist of older, higher heat rate, natural gas-fired plants in southern California. These plants, while older and less efficient than newer combined cycle plants, provide an important

reliability function and were under tolling agreements for 2007. CAISO has designated all of the units comprising El Segundo, Encina and Cabrillo II to be capacity that meets the local capacity procurement requirements of the local load-serving entities. At times, all of the plants have been designated as RMR, which entitles designated plants to certain fixed-cost payments from the CAISO for the right to dispatch those units during periods of locational constraints. Although CAISO retains the option of renewing units as RMR, the current market framework obligates Load Serving Entities to buy a portion of their capacity requirements in the local areas where their load resides. This local procurement obligation drives in part demand for RA or tolling agreements on the units.

 

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 siting permit review 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, 2007, NRG, through certain foreign subsidiaries, had investments in power generation projects located in Australia, Germany and Brazil with approximately 1,235 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 therefore concentrates 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, 2007, are summarized in the table below:

 

 

 

 

Australia — On June 8, 2006, NRG announced the sale of the Company’s 37.5% equity interest in the Gladstone power station, Gladstone, and NRG subsidiary, Gladstone Operating Services, to Transfield Services — an Australia-based company, for a purchase price of approximately $209 million (AU$239 million), subject to customary purchase price adjustments. The members of the Gladstone joint venture have withheld consent to NRG’s sale of its equity interest in the venture and the transfer of NRG’s rights and obligations in the operation and maintenance contract. NRG will continue to seek to close the transaction in 2008 as agreed or on alternative terms.

 

Germany — NRG’s interests in Germany include a 50% equity interest in MIBRAG, which mines approximately 16 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 84% 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 — Through its wholly-owned subsidiary Tosli Acquisition B.V., or Tosli, a Netherlands private limited liability company, NRG owns a 99.2% voting equity interest in a 156 MW hydroelectric power plant through Itiquira Energetica S.A., or ITISA, which is located in the state of Mato Grosso, Brazil. On December 18, 2007, NRG entered into a sale and purchase agreement to sell its 100% interest in Tosli to Brookfield Power Inc., a wholly-owned subsidiary of Brookfield Asset Management Inc., a Canadian asset management company, focused on property, power and infrastructure assets, for a purchase price of approximately $288 million, plus the assumption of approximately $60 million in debt. The sale is subject to the receipt of regulatory approval and other customary closing conditions. NRG anticipates completion of the sale transaction during first half 2008 and as discussed in Item 3 — Note 3, Discontinued Operations, the activities of Tosli and ITISA have 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 1,040 megawatts thermal equivalent, or MWt. As of December 31, 2007, NRG Thermal provided steam heating to approximately 525 customers and chilled water to 100 customers in five cities in the United States. 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 16 MW coal-fired cogeneration facility in Dover, Delaware as well as a 12 MW gas-fired project in Harrisburg, Pennsylvania. Approximately 36% 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 CFTC, FERC, NRC, PUCT and other public utility commissions in certain states where NRG’s generating assets are located. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO markets in which it participates.

 

The operations of, and wholesale electric sales from, NRG’s Texas region are not subject to rate regulation by 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

 

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. 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

 

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, 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. 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 U.S. generating facilities has either been determined by 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 FERC exclusive rate-making jurisdiction over the wholesale sale of electricity and transmission of electricity in interstate commerce. Under the FPA, 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 FERC jurisdiction to review certain transactions and numerous other activities of public utilities. NRG’s QFs are currently exempt from 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 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 United States make sales of electricity pursuant to market-based rates authorized by FERC. 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 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 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 FERC any material changes in status that would reflect a departure from the characteristics that 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 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.

 

NRG filed the most recent triennial update of its market power analysis on March 26, 2007, and this filing was accepted by FERC on August 9, 2007. On June 21, 2007, FERC issued its long-awaited final rule on market-based rates for wholesale sales of electric energy, capacity, and ancillary services. Of particular note to NRG, the new rule now requires applicants to use submarkets within an RTO region as the relevant geographic market, specifically identifying Southwest Connecticut (and the Connecticut Import interface), New York City, and PJM East as such submarkets. The impact of this rule, and any additional mitigation that may be imposed by FERC as a result of a determination of market power in a submarket, cannot be determined at this time.

 

Section 203 of the FPA requires FERC’s prior approval for the transfer of control of assets subject to FERC’s jurisdiction. Section 204 of the FPA gives FERC jurisdiction over a public utility’s issuance of securities or assumption of liabilities. However, 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 FERC.

 

In compliance with Section 215 of the Energy Policy Act of 2005, or EPAct of 2005, FERC has approved the North American Electric Reliability Corporation, or 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 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 PUHCA.

 

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 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 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 contact 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 LLC, 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.

 

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 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 ERCOT.

 

Regional Regulatory Developments

 

In New England, New York, the Mid-Atlantic region, the Midwest and California, FERC has approved regional transmission organizations, also commonly referred to as independent system operators, or ISOs. Most of these ISOs administer a wholesale centralized bid-based spot market in their regions pursuant to tariffs approved by 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 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

 

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 is expected in December 2008. In other rulemakings, the PUCT has expanded its enforcement policy, increased market oversight, and established market and generator-specific data disclosure requirements designed to increase market transparency.

 

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 Forward Capacity Market, or FCM, as discussed below. The Devon RMR Agreement terminated on December 31, 2006. On July 16, 2007, FERC conditionally accepted, subject to refund, an RMR agreement filed on April 26, 2007 by Norwalk Power for its units 1 and 2, specifying a June 19, 2007 effective date. Norwalk’s RMR rate, as well as its eligibility for the RMR agreement determined based upon the facility’s projected market revenues and costs, are subject to further proceedings. Norwalk filed for the RMR agreement in response to FERC’s order eliminating the Peaking Unit Safe Harbor bidding mechanism which took effect on June 19, 2007. In the recently-concluded FCM auction for delivery year 2010/2011, the Company sought to de-list Norwalk’s units 1 and 2. ISO-NE declined to accept that de-list bid on the grounds these units were needed for reliability. Norwalk will likely operate pursuant to an RMR agreement after June 1, 2010.

 

On December 28, 2006, the Attorneys General of the State of Connecticut and Commonwealth of Massachusetts filed in the U.S. Court of Appeals for the 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, 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.

 

New York — On July 6, 2007, FERC issued an order establishing an approximately six-month paper hearing process to address reforms to the in-city Installed Capacity, or ICAP, market and to formulate comprehensive solutions. On October 4, 2007, the NYISO filed its proposal for revisions to the ICAP market for the New York City zone. While the NYISO’s proposal will retain the existing ICAP market structure, it will impose 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 will impose a reference price on pivotal suppliers and require bids to be submitted at or below the reference price. The reference price will be 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 proposal is expected to result in a significant decrease in the clearing price for New York City ICAP. Earlier this year, FERC had rejected proposed mitigation that would have effectively lowered the capacity offer cap for those units from $105/kW-year to $82/kW-year. Although that proposal was rejected on March 6, 2007, FERC initiated an investigation to determine the justness and reasonableness of the NYISO’s in-city installed capacity market, setting a refund effective date of May 12, 2007. The NYISO’s October 4, 2007, filing proposes that any market reforms should be implemented only prospectively and that no refunds should be required.

 

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. On December 14, 2007, the NYSRC approved a 2008 IRM of 15%, which is a reduction of 1.5% from last year’s requirement and effectively offsets any increased demand for capacity that would have occurred due to load growth. Additionally, on January 29, 2008, FERC accepted the NYISO’s installed capacity demand curves for 2008/2009, 2009/2010, and 2010/2011. The demand curves serve as a critical determinant of capacity market prices, and if approved, would potentially increase prices slightly in the rest-of-state market while reducing prices below their current levels in the New York City market for the next two years, all other factors remaining constant.

 

PJM — On December 22, 2006, FERC issued an order approving the settlement agreement filed September 29, 2006, in the Reliability Pricing Model, or RPM, proceeding establishing a new capacity market mechanism, the key components of which include the determination of capacity prices through use of a downward-sloping demand curve, locational pricing, and a forward capacity market. PJM has conducted the RPM auctions for the 2007/2008, 2008/2009, 2009/2010, and 2010/2011 delivery years, and has been operating under the RPM since June 1, 2007. Several parties, however, have appealed the FERC’s order accepting the settlement. A successful appeal could potentially disrupt RPM implementation and create a refund obligation. On January 31, 2008, PJM submitted to FERC a proposal to increase its Cost of New Entry, which is a critical component of the demand curve in the RPM market, for the 2011/2012 delivery year. PJM’s proposed increase is opposed by consumer interests.

 

South Central Region

 

Entergy has begun to implement its Independent Coordinator of Transmission, or ICT, proposal that will provide (i) independent oversight over the operations of the Entergy transmission system, including the processing of interconnection and transmission requests; (ii) a new process and standard for assigning cost responsibility for transmission upgrades; and (iii) a new weekly procurement process that will allow both Entergy and NRG, as a purchaser of power, to more efficiently utilize the transmission system. The Southwest Power Pool has been selected as the ICT and began performing its responsibilities in November 2006.

Entergy’s ICT proposal will impact the region’s existing operations by revising the manner in which transmission service is obtained. Compounding the uncertainty caused by the transition to the ICT, FERC has promulgated new regulations with respect to its pro-forma open access transmission tariff, referred to as Order No. 890, that may affect South Central’s ability to transmit, and thus buy and sell, power.

 

West Region

 

California has transitioned to a market structure where load-serving entities, or 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, although CAISO retains the option of renewing RMR agreements as necessary to maintain local reliability. During 2008, only Cabrillo Power II LLC will be operating under an RMR agreement, and only for ten of its twelve peaking units. Cabrillo Power I LLC’s Encina facility terminated its RMR agreement with CAISO effective December 31, 2007. Please see the Regional Business Description for a discussion of the contracting activities that have occurred on the units pursuant to the state’s RA program.

 

There is no organized capacity market in California. As noted above, the CPUC has imposed local capacity requirements on load-serving entities but the application of this Resource Adequacy Capacity Product obligation is uneven. On December 20, 2007, FERC ordered the CAISO to extend its Reliability Capacity Services Tariff, which was set to expire on December 31, 2007, until the implementation of the CAISO’s Market Redesign and Technology Upgrade, or MRTU, or an alternate backstop capacity procurement mechanism, and initiated an investigation into the justness and reasonableness of the existing capacity procurement process. It is unclear what compensation will be provided to generators needed for reliability purposes. In addition, several generators, including El Segundo Power, LLC, filed a complaint at FERC on November 30, 2007, similarly seeking just and reasonable compensation for the value of capacity-related reliability services.

 

On September 21, 2006, FERC conditionally accepted the MRTU proposal which is currently scheduled to go into effect during 2008. 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. Several parties have appealed FERC’s orders accepting the MRTU proposal, seeking to materially modify the proposal and/or delay its implementation.

 

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 U.S Environmental Protection Authority, or USEPA, published the Clean Air Mercury Rule, or CAMR, to permanently cap and reduce mercury emissions from coal-fired power plants. CAMR imposes

limits on mercury emissions from new and existing coal-fired plants and creates a market-based cap-and-trade program that will reduce nationwide utility emissions of mercury in two phases, 2010 and 2018. The rule was challenged by New Jersey and ten other states. On February 8, 2008, the U.S. Court of Appeals for the D.C. Circuit vacated USEPA’s rule delisting coal- and oil-fired electric generating units from regulation under CAA §112 (the “Delisting Rule”) and CAMR. More specifically, cap and trade, allowing power plants to meet emission targets by buying credits, was struck. The three-judge panel agreed with the states that challenged the rule that the USEPA did not have the authority to exempt power plants. Certain states in which NRG operates coal plants, such as Delaware, Massachusetts and New York adopted state implementation plans which did not permit trading in lieu of the CAMR federal implementation plan. Texas and Louisiana adopted the federal CAMR through the state implementation plan, or SIP process. USEPA has already approved the Louisiana SIP, but Texas has not yet been approved. At this time, it is unclear how programs in these states will be affected by the Court’s actions.

 

On May 12, 2005, the USEPA published the Clean Air Interstate Rule, or CAIR. This rule applies to 28 eastern states and the District of Columbia, or D.C., and caps both SO₂ and NO_x emissions from power plants in two phases; 2010 and 2015 for SO₂ and 2009 and 2015 for NO_x. CAIR will apply to some of the Company’s power plants in New York, Massachusetts, Connecticut, Delaware, Louisiana, Illinois, Pennsylvania, Maryland and Texas. On August 24, 2005, the USEPA published a proposed FIP to ensure that generators affected by CAIR reduce emissions on schedule. Furthermore: (i) on December 20, 2005, the USEPA signed proposed revisions to address attainment for fine particulates, or NAAQS for PM2.5, which will require affected states to implement further rules to address SO₂ and NO_x emissions; and (ii) on November 9, 2005, the USEPA proposed the second phase of the 8-hour ozone NAAQS rule relating to NO_x emissions. A number of environmental groups, states and industry organizations challenged aspects of CAIR. The challenges were consolidated into South Coast Air Quality Management District v. EPA. In a ruling on December 22, 2006, the D.C. Circuit overturned portions of USEPA’s Phase I implementation rule for the new 8-hour ozone standard. Specifically, the court ruled that 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 Clean Air Act, or the CAA, on volatile organic carbon, or VOC, and NO_x 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 California, New York City and Texas.

 

The clean air visibility rule was published by the USEPA on July 6, 2005. The rule requires regional haze controls by targeting SO₂ and NO_x emissions from sources including power plants of a certain vintage through the installation of Best Available Retrofit Technology, or BART, in certain cases. States were required to develop implementation plans by December 2007. Most of the Company’s facilities will likely be able to satisfy their obligations under the BART rule through compliance with the more stringent CAIR. Accordingly, no material additional expenditures are anticipated by the Company beyond those required by CAIR.

 

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 an 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.

 

There is a growing consensus in the U.S. and globally that GHG emissions are a major cause of global warming. 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 U.S. Supreme Court found that CO₂, the most common GHG, could be regulated as a pollutant and that the USEPA should regulate CO₂ emissions from mobile sources. Since power plants, particularly coal-fired plants, are a significant source of GHG emissions both in the United States and globally, it is almost certain that GHG regulatory actions will encompass power plants as well as other GHG emitting stationary sources. In 2007, in the course of producing approximately 80 million MWh of electricity,

NRG’s power plants emitted 68 million tonnes of CO₂, of which 61 million tonnes were emitted in the United States, 3 million tonnes in Australia and 4 million tonnes in Germany.

 

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 GHG emissions allowances without having to purchase them in an auction or on the open market. For example, the U.S. Senate is currently considering climate change legislation sponsored by Senators Lieberman and Warner. If legislation with the same level of allocations to existing generation resources and emissions reductions as those contained in the current version of the Lieberman-Warner legislation were enacted, NRG expects that the legislation will have minimal impact on the Company’s financial performance through the next decade. Thereafter, under such legislation as currently drafted, the impact on NRG would depend on the Company’s level of success in developing and deploying low and no carbon technologies being pursued as part of our RepoweringNRG and econrg initiatives.

 

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 2nd 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 and restricted their ability to allow generators to substitute mitigation for aquatic specie losses through habitat restoration or other measures. 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 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 consultations on the plans have occurred with USEPA or its delegated state or regional agencies, and 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 U.S. 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 Act, owners of nuclear plants, including the owners of STP, entered into contracts setting out the obligations of the owners and the U.S. 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. The state of Texas has agreed to a compact with the state of Vermont for a disposal facility that would be located in Texas. That compact was ratified by Congress and signed by President Clinton in 1998. 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 U.S. Environmental Initiatives

 

Northeast Region

 

NRG’s facilities in the eastern U.S. are subject to a cap-and-trade program governing NO_x emissions during the ozone season, which typically begins May 1 and lasts through September 30. These rules essentially require that one NO_x allowance be held for each ton of NO_x emitted. Each of NRG’s facilities that are subject to these rules have been allocated NO_x emission allowances. NRG currently estimates that its total NO_x emission allowances is sufficient to generally cover operations at these facilities through 2009, reflecting the fact that NO_x allowances are allocated on a three-year, look-back basis. However, if at any point the Company’s NO_x emission allowances are insufficient for the anticipated operation of each of these facilities, NRG must purchase NO_x allowances. Any obligation to purchase a substantial number of additional NO_x emission allowances could have a material adverse effect on the Company’s results of operations, financial position and cash flows.

 

The Ozone Transport Commission, or OTC, was established by Congress and governs ozone and the NO_x budget program in certain eastern states, including Massachusetts, Connecticut, New York and Delaware. The OTC proposes to implement a regional plan containing emission reduction targets for power plants that exceed those under CAIR. The OTC targets and timelines are implemented on a state by state basis. Current attention is focused on NO_x emissions from units run primarily on High Energy Demand Days, or HEDD, of which NRG owns facilities in Connecticut, Delaware and New York. NRG continues to be actively engaged in the OTC stakeholder process including providing technical expertise to improve policy decision making. While it is not possible to predict the outcome of this regional effort, to the extent that the OTC is successful in implementing emission requirements that are more stringent than existing regimes, NRG could be materially impacted.

 

On December 20, 2005, several northeastern states entered into a Memorandum of Understanding, or MOU, to create a RGGI to establish a cap-and-trade GHG program for electric generators. The RGGI states are now in the process of promulgating state regulations needed for implementation. To date, all declared states have selected, with the exception of specific set asides, to auction all of the allowances. With state legislation and regulation in place, the first regional auction of RGGI allowances needed by power generators could be held as early as the summer of 2008. Approximately 12 million tonnes of CO₂ were emitted from the Company’s generating units in Connecticut, Delaware, Maryland, Massachusetts and New York that will likely be subject to RGGI 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 CO₂ emissions, cannot be predicted. However, NRG believes that due to the absence of 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.

 

New England — Massachusetts air regulations prescribe schedules under which six existing coal-fired power plants in-state are required to meet stringent emission limits for NO_x, SO₂, mercury, and CO₂. NRG’s Somerset plant is subject to these regulations. NRG has installed natural gas reburn technology to meet the NO_x and SO₂ limits. On June 4, 2004, the Massachusetts Department of Environmental Protection, or MADEP, issued its regulation on the control of mercury emissions. The effect of this regulation is that starting October 1, 2006, Somerset will be capped at 13.1 lbs/year of mercury as of January 1, 2008 and must achieve a reduction in its mercury inlet-to-outlet concentration of 85%. NRG plans to meet the requirements through the management of its fuels and the use of early and off-site reduction credits. Additionally, NRG has entered into an agreement with MADEP to retire or repower the Somerset station by the end of 2009. A permit for repowering the facility was approved by the MADEP in 2007.

 

The Massachusetts carbon regulation 310 CMR 7.29 Emissions Standards for Power Plants requires coal-fired generation located within the state to comply with CO₂ emissions restrictions. A carbon emissions rate requirement will apply in 2008. It is expected that Somerset will purchase offsets to comply.

 

New York — NRG’s Huntley Power LLC, Dunkirk Power LLC and Oswego Power LLC entered into a Consent Order with the New York State Department of Environmental Conservation, or NYSDEC, effective March 31, 2004, regarding certain alleged opacity exceedances. The Order stipulates penalties for future violations of opacity requirements and compliance will be achieved with the installation of baghouses to further control particulates at

the Huntley and Dunkirk facilities in 2008 and 2009, respectively. In 2007, NRG accrued amounts payable to NYSDEC of $0.3 million to cover the stipulated penalty payments.

 

Delaware — In November 2006, the Delaware Department of Natural Resources and Environmental Control, or DNREC, promulgated Regulation No. 1146, or Reg 1146, Electric Generating Unit Multi-Pollutant Regulation and Section 111(d) of the State Plan for the Control of Mercury Emissions from Coal-Fired Electric Steam Generating Units. These regulations govern the control of SO₂, NO_x, and mercury emissions from electric generating units. NRG’s plan to install controls at the Company’s Indian River facility, while on an accelerated basis, was unable to meet certain deadlines, taking into account the time required, as a practical matter, to design, install and commission the necessary equipment. NRG filed a challenge to Reg 1146 with the Environmental Appeals Board, or EAB, on December 6, 2006. In addition, NRG also filed a protective appeal with the Delaware Superior Court on December 29, 2006. This challenge was settled when DNREC and NRG signed a Consent Order on September 25, 2007, and filed that document with the Delaware Superior Court thereby ending the case. Under this agreement, continued operations at the Company’s Indian River Generating Station are conditioned upon installation of controls on Units 1 and 2 by May 1, 2008, to reduce NO_x; installation of controls on Units 1-4 by January 1, 2009 to meet mercury requirements; mothball of Units 1 and 2 by May 1, 2011, and May 1, 2010, respectively; and installation of advanced controls on Units 3 and 4 in 2011 to further reduce NO_x and SO₂. If the plant emits NO_x in excess of 1,700 tons in any given ozone season, it will be subject to a graduated scale of stipulated penalties, up to a maximum $2,500/ton. The capital costs associated with this settlement are included in the Company’s estimated environmental capital expenditures. 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.

 

West Region

 

On September 27, 2006, Governor Arnold Schwarzenegger signed Assembly Bill 32, or AB32, California Global Warming Solutions Act of 2006. AB 32 requires the California Air Resources Board, or CARB, to develop a GHG reduction program to reduce emissions to 1990 levels by 2020, a reduction of approximately 25%. The reductions are to be phased in beginning 2012 pursuant to regulations to be adopted by 2011. NRG does not expect that implementation of AB32 in California will 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 Clean Air Act from the United States Environmental Protection Agency, or USEPA, seeking information primarily related to physical changes made at the Big Cajun II plant, and subsequently received a notice of violation, or 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. Discussions with the USEPA are ongoing and the Company cannot predict with certainty the outcome of this matter.

 

Nuclear Insurance

 

STPNOC purchases insurance coverage on behalf of NRG and the other owners of STP. STP maintains property, decontamination liability and nuclear hazard liability insurance coverage as required by law and periodically reviews available limits and coverage for additional protection. Currently, STP has a $2.75 billion limit in property and decontamination liability insurance coverage, which is above the legally required minimum of $1.06 billion. The $2.75 billion includes $1 billion excess blanket coverage that is shared with two other nuclear power plants, namely Diablo Canyon and D.C. Cook. The deductible for property damage is $2.5 million. STP also

carries a primary accidental outage policy, which allows for six weeks of indemnity at $3.5 million per week after a 17 week deductible is met. The $3.5 million weekly indemnity would be allocated between the three owners of STP according to their ownership percentages. NRG has purchased additional accidental outage coverage for its 44% ownership stake in STP. This policy provides coverage after the six week indemnity period has been paid under the primary policy, and will provide NRG $1.98 million weekly indemnity per unit for 52 weeks and $1.58 million per week for the next 71 weeks. If both units at STP are affected by an outage arising out of the same accident, weekly indemnity per unit is limited to 80% of the single unit recovery. There is no coverage for partial outages, and the outage must be the result of a property damage caused by a sudden and fortuitous event.

 

The Price-Anderson Act, as amended through 2025 by the Energy Policy Act of 2005, requires owners of nuclear power plants in the U.S. to purchase the maximum amount of insurance available (currently $300 million) in the insurance market for liability claims that arise in the event of a nuclear accident. In addition, the Act provides a secondary layer of protection of up to $10.5 billion. Under this provision, each licensed reactor company is obliged to contribute up to approximately $101 million per unit per accident in retrospective premiums for any single incident at any nuclear power plant. Annual installments per reactor cannot exceed $15 million. STP is a two reactor facility but NRG’s liability would be capped at 44% due to the Company’s ownership interest in STP. The Price-Anderson Act only covers nuclear liability associated with an accident in the course of operation of the nuclear reactor, transportation of nuclear fuel to the reactor site, 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. Any substantial retrospective premiums imposed under the Price-Anderson Act or losses not covered by insurance could have a materially adverse effect on NRG’s financial condition, the results of operations and statement of cash flows.

 

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 DNREC stating that it may be a potentially responsible party with respect to a historic captive landfill. On October 1, 2007, NRG filed a Facility Evaluation with DNREC, through the Voluntary Clean-up Program to investigate the site. DNREC responded to the Facility Evaluation on February 4, 2008 finding 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 is completed, the Company is unable to predict the impact of any required remediation.

 

Further details regarding the Company’s Domestic Site Remediation obligations can be found in Item 15 — Note 22, Regulatory 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 U.S., 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 — On June 22, 2007, Germany enacted the German National CO₂ Allocation Plan 2008 — 2012, in which MIBRAG was granted CO₂ allocations that are less than the needs of its three generating plants. The financial impact of this regulation on MIBRAG’s results is not yet clear and management of MIBRAG is implementing a number of options to minimize any adverse impact. MIBRAG has also submitted an application under the hardship clause of the law to receive a higher allocation of the CO₂ allowances. The cost of compliance with the CO₂ regulation for NRG’s Schkopau plant is expected to be passed through to its off-taker of energy under 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, 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 Securities and Exchange Commission.

 

 

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 marginal cost natural gas-fired power plants that currently have substantially higher variable costs than NRG’s coal-fired baseload power plants. The current pricing and cost environment 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 but would generally not affect the cost of the coal that the plants use. This 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, generation 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 2013, 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 are likely to deteriorate over time as the rural cooperatives grow their customer base, 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. 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 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. Economic hedges will not necessarily qualify for cash flow hedge accounting treatment. As a result, the Company may be unable to accurately predict the impact that its risk management decisions may have on its quarterly and annual operating results.

 

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 emissions 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 RepoweringNRG 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 RepoweringNRG projects could have a negative impact on the credit ratings of NRG.

 

As part of the RepoweringNRG 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 the Company 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 California ISO, New York ISO and New England 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 U.S. 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 Federal Power Act, or 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 United States make sales of electricity in interstate commerce and are public utilities for purposes of the FPA. 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 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 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 Nuclear Regulatory Commission, or 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 U.S. Nuclear Waste Policy Act of 1982 to accept and dispose of STP’s spent nuclear fuel. See also “Environmental Matters — U.S. Federal Environmental Initiatives — Nuclear Waste” in Item 1. 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 United States 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. Future federally imposed changes in the National Ambient Air Quality Standard for ozone could result in additional reduction of NO_x limits or reduced compliance flexibility for power generating units. Challenges to CAMR, if successful, could result in a unit by unit command and control approach to mercury resulting in additional controls to NRG coal facilities in Louisiana and Texas.

 

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.

 

There is a growing consensus in the U.S. and globally that GHG emissions are a major cause of global warming. 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. Earlier this year, the U.S. Supreme Court found that CO₂, the most common GHG, could be regulated as a pollutant and that the USEPA should regulate CO₂ emissions from mobile sources. Since power plants, particularly coal-fired plants, are a significant source of GHG emissions both in the United States and globally, it is almost certain that GHG regulatory actions will encompass power plants as well as other GHG emitting stationary sources. In 2007, in the course of producing approximately 80 million MWh of electricity, NRG’s power plants emitted 68 million tonnes of CO₂, of which 61 million tonnes were emitted in the United States, 3 million tonnes in Australia and 4 million tonnes in Germany.

 

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 GHG emissions allowances without having to purchase them in an auction or on the open market.

 

State and regional initiatives such as the RGGI, in the Northeast, and the Western Climate Initiative, or WCI, are developing market based programs to counteract climate change. The RGGI states are in the process of promulgating state regulations needed for implementation with six of the ten states issuing drafts for comment. With state legislation and regulation in place, the first regional auction of RGGI allowances needed by power generators could be held as early as the summer of 2008.

 

However, of the approximately 61 million tonnes of CO₂ emitted by NRG in the United States in 2007, approximately 12 million tonnes were emitted from the Company’s generating units in Connecticut, Delaware, Maryland, Massachusetts and New York that will likely be subject to RGGI 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 CO₂ emissions, cannot be predicted. However, NRG believes that due to the absence of 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, 2007, approximately 66% of NRG’s employees at its U.S. 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 U.S. investments do not have.

 

NRG has investments in power projects in Australia, Germany and Brazil. 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 occurances 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 Financial Accounting Standard No. 142, Goodwill and Other Intangible Assets, 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.

 

Because the historical financial information may not be representative of the results of operation as a combined company or capital structure after the Acquisition, and NRG’s and Texas Genco LLC’s historical financial information are not comparable to their current financial information, you have limited financial information on which to evaluate the combined company, NRG and Texas Genco LLC.

 

Texas Genco LLC did not exist prior to July 19, 2004, and Texas Genco LLC and its subsidiaries had no operations and no material activities until December 15, 2004 when Texas Genco LLC acquired its gas- and coal-fired assets. Consequently, Texas Genco LLC’s historical financial information is not comparable to the Texas region’s current financial information.

 

NRG and Texas Genco LLC had been operating as separate companies prior to February 2, 2006. NRG and Texas Genco LLC had no prior history as a combined company, nor have they been previously managed on a combined basis. The historical financial statements may not reflect what the combined company’s results of operations, financial position and cash flows would have been had both companies operated on a combined basis and may not be indicative of what the combined company’s results of operations, financial position and cash flows will be in the future.

 

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 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 NRG’s 2007 Annual Report on Form 10-K 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.

 

 

None.

 

 

Listed below are descriptions of NRG’s interests in facilities, operations and/or projects owned as of December 31, 2007. The MW figures provided represent nominal summer net megawatt capacity of power generated as adjusted for the Company’s ownership position excluding capacity from inactive/mothballed units as of December 31, 2007. The following table summarizes NRG’s power production and cogeneration facilities by region: