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:

 

 

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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ     Accelerated filer o     Non-accelerated filer o

 

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 $6,599,652,171 based on the closing sale price of $48.18 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 2007 Annual Meeting of Stockholders to be held on April 25, 2007

 

 

TABLE OF CONTENTS

 

INDEX

 

 

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

 

 

General

 

NRG Energy, Inc., 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 primarily 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 internationally. As of December 31, 2006, NRG had a total global portfolio of 223 active operating generation units at 51 power generation plants, with an aggregate generation capacity of approximately 24,175 MW. Within the United States, the Company has one of the largest and most diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with approximately 22,940 MW of generation capacity in 207 active generating units at 45 plants. These power generation facilities are primarily located in Texas (approximately 10,760 MW), and the Northeast (approximately 7,240 MW), South Central (approximately 2,850 MW), and the West (approximately 1,965 MW) regions of the United States, with approximately 125 MW from the Company’s thermal assets. NRG’s principal domestic power plants consist of a diversified mix of natural gas-, coal-, oil-fired and nuclear facilities, representing approximately 45%, 34%, 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, and consist primarily of baseload, intermediate and peaking power generation facilities, which are referred to as the merit order, and also 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 diverse 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. In addition, NRG is pursuing opportunities to repower existing facilities and develop new generation capacity in markets in which NRG currently owns assets in an initiative referred to as Repowering NRG. In connection with NRG’s acquisition of Padoma Wind Power LLC, the Company has and will continue to actively evaluate and potentially develop or construct domestic terrestrial wind projects as part of the Repowering NRG program.

 

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 elements:

 

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. In furtherance of this goal, NRG has initiated a company-wide program, known as Repowering NRG, 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 merit order; increased technological and fuel diversity; and reduced environmental impacts, including facilities that either have near zero greenhouse gas emissions or can be equipped to capture and sequester greenhouse gas emissions.

 

Increase value from existing assets — NRG has a highly diversified portfolio of power generation assets in terms of region, fuel-type and dispatch levels. 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 improve the Company’s return on invested capital, or ROIC — a strategy that NRG has branded FORNRG, or Focus on ROIC@NRG.

 

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, NRG expects to continue its practice of returning excess cash flows to its debt and equity investors on a regular basis.

 

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 expertise in marketing power and ancillary services, its knowledge of markets, its balanced financial structure and its diverse portfolio of power generation assets.

 

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 regions. 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 owning multiple plants in its 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 against 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 22,940 MW of generation capacity in 207 active generating units at 45 plants as of December 31, 2006. 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 8,745 MW of generation capacity measured as of December 31, 2006, provide the Company with a significant source of stable cash flow, while its intermediate and peaking facilities, with approximately 14,195 MW of generation capacity as of December 31, 2006, 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, 2006:

 

 

Reliability of future cash flows — NRG has sold forward or otherwise hedged a significant portion of its expected baseload generation capacity through 2012. 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, 2006, the Company has purchased forward under fixed price contracts (with contractually-specified price escalators) to provide fuel for approximately 73% of its expected baseload coal generation output from 2007 to 2012. 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 market dynamics for baseload power plants — In 2006, approximately 83% of the Company’s domestic generation was 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 these ERCOT assets 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 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 through 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 are often ideally situated for repowering or the addition of new capacity, as well, 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, 2006. The table also reflects the realignment of the Company’s new segment structure 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:  The percentage of time in one year that a generating unit is able to produce electricity, adjusted to take into account times when the unit is unavailable and able to produce its full rated output.

 

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 that it takes 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, 2006 and 2005:

 

 

 

 

 

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, 2006, the Company’s power generation assets consisted of approximately 10,470 MW of gas-fired; 7,815 MW coal-fired; 3,555 MW of oil-fired and 1,100 MW of nuclear generating capacity in the United States. In addition, NRG also owns approximately 1,230 MW of thermal capacity 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 39% baseload, 37% intermediate and 24% 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 resulting from baseload hedge agreements extending beyond December 31, 2006 through 2012:

 

 

 

 

The following is a discussion of NRG’s generation assets by segment for the year ended December 31, 2006. This discussion reflects the realignment of the Company’s new segment structure as discussed in Item 15 — Note 17, Segment Reporting, to the Consolidated Financial Statements in this Form 10-K.

 

Texas Region — As of December 31, 2006, NRG’s generation assets in the Texas region consisted of approximately 5,280 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 STP which uses nuclear fuel. Power plants are generally dispatched in order of lowest operating cost and as of December 31, 2006, 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, subject to planned and forced outages.

 

Northeast Region — As of December 31, 2006, NRG generation assets in the Northeast region of the United States consisted of approximately 7,240 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, 2006, NRG’s generation assets in the Northeast region consisted of approximately 1,960 MW of baseload generation assets and approximately 5,280 MW of intermediate and peaking assets.

 

South Central Region — As of December 31, 2006, NRG generation assets in the South Central region of the United States consisted of approximately 2,850 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. An annual average of 1,164 MW of baseload generation capacity has been contracted through eleven cooperatives within the region through 2025.

 

West Region — On March 31, 2006, NRG acquired Dynegy, Inc.’s 50% ownership interest in WCP Holdings to become sole owner of power plants with generation capacity of approximately 1,825 MW in the West region of the United States. These assets, combined with approximately 140 MW of existing wholly owned capacity in the Western Electricity Coordinating Council, brings NRG’s total generation to approximately 1,965 MW in the West region as of December 31, 2006. 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. Excluding these two plants, total generation for the West region was 1,870 MW.

 

International Region — As of December 31, 2006, 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 owned equity interests in certain coal mines in Germany.

 

Thermal — NRG owns thermal and chilled water businesses that generate approximately 1,230 MW thermal equivalents. In addition, NRG’s thermal segment owns certain power plants with approximately 125 MW of power generating capacity located in Delaware and in Pennsylvania.

 

Dispositions of Non-Strategic Assets

 

During 2006, NRG continued its efforts to divest the Company’s interests in non-core assets. As of December 31, 2006, NRG had sold a number of consolidated businesses and equity investments in an effort to reduce the Company’s debt, improve liquidity and rationalize NRG’s investments.

 

Dispositions completed during 2006 are summarized in the following table:

 

 

 

 

In addition, on January 3, 2007, NRG completed the sale of Red Bluff and Chowchilla II power plants to an entity controlled by Wayzata Investment Partners LLC.

 

Repowering NRG Program

 

NRG has announced a comprehensive portfolio redevelopment program, referred to as Repowering NRG, which involves the development, financing, 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 the Repowering NRG program, the Company anticipates retiring certain existing units and adding up to approximately 10,350 MW of new generation, with an emphasis on new baseload capacity that is supported by long-term power purchase agreements, or PPAs, and financed with limited or non-recourse project financing. NRG expects 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 expects that the Repowering NRG program will also result in indirect benefits, including the continuation of operations and retention of key personnel at its existing facilities.

 

A critical aspect of the Repowering NRG program is the extent to which the Company seeks to reduce the carbon intensity of the Company’s generation fleet by developing generating facilities with zero CO₂ and low CO₂ emissions, as well as facilities that can be equipped for CO₂ separation and sequestration. As a result, the Repowering NRG program is important not only to NRG but also to the power industry in general. The American power industry is the primary emitter of CO₂ in the largest CO₂ emitting market on earth. As the power industry takes steps to develop the next wave of power generation infrastructure, technology and capital allocation decisions will be made which could impact GHG from power generation by either making the situation significantly worse or significantly better in terms of CO₂ intensity. Although there is no current technological solution to retro-fit existing fossil-fueled technology to capture GHG from power plant flues, there are commercially available large scale technologies for new plants that can generate power with much lower GHG emissions than traditional coal-fired generation. Given that new generation units have useful lives of up to 50 years, NRG will give full consideration to CO₂ and other emissions that contribute to GHG when making its long-term investment decisions.

 

As part of the Repowering NRG program, NRG is pursuing a five-pronged GHG emissions strategy as follows:

 

1. Nuclear development — a known, reliable source of electricity with zero emissions.

 

2. IGCC development — coal-fueled baseload generation designed to reduce the intensity of CO₂ emissions.

 

3. Wind development — renewable energy for the future with zero emissions.

 

4. Public outreach — NRG will work with government, industry and public interest groups to formulate and implement an economically and environmentally responsible GHG policy.

 

5. Bridge the technology gap — The Company has launched a number of initiatives to improve technology through R&D particularly post-combustion carbon capture, developing underground sequestration, and finding offsets that will mitigate CO₂ production.

 

NRG estimates that the Repowering NRG program, if fully implemented as currently proposed, could have a total capital cost of approximately $16 billion. While NRG believes it is extremely unlikely that the program will be fully implemented as currently proposed, the Company nonetheless expects the overall capital expenditures in connection with the program will be substantial. NRG expects to mitigate the capital cost of the program through equity partnerships and public-private partnerships, as well as through development fees for certain projects. To mitigate the investment risks, NRG anticipates entering into long-term PPAs and engineering, procurement and construction, or EPC, contracts. The Company currently expects its share of cash contributions for the projects included in the Repowering NRG program to range between $500 million and $2.0 billion over the next decade. However, the proposed increase in generation capacity and capital costs resulting from Repowering NRG could change as proposed projects are included or removed from the program due to a number of factors, including successfully obtaining required permits and long term PPAs, availability of financing on favorable terms, and

achieving targeted project returns. The projects that have been identified as part of the Repowering NRG program are 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 table summarizes the current projects included in the Repowering NRG program by fuel-type:

 

 

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. Natural gas swap agreements and other financial instruments hedge the price NRG will receive for power to be delivered in the future.

 

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 is 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 based on forecasted generation and market volatility. As of December 31, 2006, NRG has purchased forward under contracts to provide fuel for approximately 73% on average of the Company’s requirement from 2007 through 2012; 111% in 2007 (includes inventory build in excess of the Company’s forecasted coal burn requirements), 89% in 2008, 81% in 2009, 56% in 2010, 51% in 2011 and 50% in years 2012 and beyond. 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 35 million tons of coal in 2006, which would rank NRG as one of the largest coal purchasers in the United States.

 

As of December 31, 2006, NRG had approximately 7,600 privately leased or owned rail cars in the Company’s transportation fleet. In addition, the Company intends to enter into contracts for delivery of additional 1,100 rail cars within the next year of which approximately 1,000 will replace a portion of the Company’s existing rail car 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 comprised of primarily 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 gas on units that may not run. The Company contracts for gas storage services as well as gas transportation services to ensure delivery of gas when needed.

 

Nuclear Fuel — STP’s owners satisfy STP’s fuel supply requirements by (1) acquiring uranium concentrates and contracting for conversion of the uranium concentrates into uranium hexafluoride, (2) contracting for enrichment of uranium hexafluoride and (3) 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 the highest in its 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.

 

Plant 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 get the best results for the Company. Performance goals are set for equivalent forced outage rates, or EFOR, availability, procurement costs, operating costs and safety.

 

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

 

To support the Repowering NRG program, the Company has organized its project execution process into one centralized group consisting of engineering, procurement and construction. This group has regional engineering functions combined with corporate project engineering, project management, procurement and construction functions to provide a consistent and standardized approach to the way repowering work is executed. 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.

 

Performance Improvement, Cost and Process Control Initiatives

 

In 2005, NRG introduced a comprehensive, company-wide cost and revenue enhancement program with the goal of increasing its return on invested capital, or ROIC. This effort has been branded as FORNRG, or Focus on ROIC@NRG. Projects are focused on improving plant performance, reducing purchasing and other costs and streamlining processes. A large number of initiatives are currently under way at NRG’s major baseload facilities, including forced outage reductions, achieving full load, station service reductions, and heat rate improvements. Qualifying projects are also underway at the Princeton headquarters, which have reduced paperwork burdens as well as tax and insurance costs.

 

During the second quarter 2006, NRG expanded the program to include the Texas Genco assets and extended the term of the program to 2009, with anticipated annual savings in excess of $200 million to be achieved through

continued benefits from operational performance, cost synergies and purchasing-related initiatives, plus $50 million in cash savings. For 2006, the program has demonstrated benefits of over $140 million from operational performance, cost synergies and purchasing-related initiatives, plus $61 million in cash savings, putting the Company on track to meet its 2009 target.

 

Environmental Capital Expenditures

 

Based on current rules, technology and plans, NRG has estimated that approximately $1.28 billion of environmental capital expenditures will be incurred during the period 2007 through 2012, primarily related to installation of particulate, SO₂, NO_x, and mercury controls to comply with the Clean Air Interstate Rule and Clean Air Mercury rules or alternative State regimes, to the extent more stringent than the USEPA rules, as well as installation of BTA under the Phase II 316(b) Rule. Changes to regulations or market conditions could result in changes to installed equipment timing or associated costs.

 

The following table summarizes the estimated environmental capital expenditures for the referenced period, by region and by year:

 

 

NRG is working to reduce a portion of the above environmental capital expenditures. First, NRG has the ability to monetize a portion of the Company’s excess allowances over the 2007-2012 timeframe and still hold sufficient allowances to operate the fleet with proposed controls through at least 2020. Second, 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 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.

 

  Employees

 

As of December 31, 2006, NRG had 3,217 employees, approximately 1,622 of whom were covered by U.S. bargaining agreements. During 2006, the Company did not experience any significant labor stoppages or labor disputes at any of its facilities.

 

Regional Business Descriptions

 

NRG is organized into business units as described below, with each of the Company’s core regions operating as a separate business segment. As of December 31, 2006, NRG realigned the Company’s segment structure. For a further discussion on the realignment of the Company’s operating segments and for financial information on NRG’s operations by segment, see Item 15 — Note 17, Segment Reporting, to the Consolidated Financial Statements.

 

TEXAS

 

NRG’s largest business unit 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 regionally diverse 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 (1) ensure the availability of the baseload plants to fulfill their commercial obligations under long-term forward sales contracts already in place, (2) manage the gas assets for profitability while ensuring the reliability and flexibility of power supply to the Houston market, (3) 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 (4) 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 a dual path of 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. For the gas-fired capacity sold forward, the Company will offer a range of products including where the customer has the right to dispatch capacity as the customer 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 economic to run.

 

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

 

 

 

 

Generation Facilities

 

As of December 31, 2006, NRG’s generation facilities in Texas consisted of approximately 10,760 MW of generation capacity. The following table describes NRG’s electric power generation plants and generation capacity as of December 31, 2006:

 

 

 

 

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 2,480 MW as of December 31, 2006. Two of these units are 650 MW steam units that were placed in commercial service in December 1977 and December 1978, respectively. The other two units are 570 MW and 610 MW steam units that were placed in commercial service in June 1980 and December 1982, respectively. 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 SCR, 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. Plant uprate projects completed in 2006 uprated the net generation capacity of W.A. Parish by 17 MW.

 

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 1,700 MW as of December 31, 2006. The first unit is an 835 MW steam unit that was placed in commercial service in December 1985. The second unit is an 865 MW steam unit that was placed in commercial service in December 1986. Limestone primarily burns lignite from an on-site 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. NRG owns the mining equipment and facilities and a portion of the lignite reserves located at the 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. Both units have installed low-NO_x burners to reduce NO_x emissions and scrubbers to reduce SO₂ emissions. In the second quarter of 2006, NRG replaced the high pressure and intermediate pressure turbines, rewound the generator and replaced the main generator step-up transformer of Limestone Unit 2. These upgrades increased the generation capacity by 86 MW.

 

South Texas Project Electric Generating Station, or STP — 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 1,250 MW of generation capacity. STP’s two generation units commenced operations in August 1988 and June 1989, respectively. For the year ended December 31, 2006, 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%, approximately 1,100 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 all decisions 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.

 

Repowering NRG — Texas

 

As part of the Company’s Repowering NRG program, NRG has identified a number of proposed projects in Texas that could add important generation capacity to the State. These include, at present, one or more Houston gas-fired generation projects and wind projects, a large baseload coal project, and two new nuclear units. These projects are designed to meet the growing electrical needs of the State of Texas in a pragmatic and environmentally responsible way. Using a balanced portfolio of fuels and technologies, these projects would provide Texas with both new baseload generation, as well as intermediate and peaking generation units that will follow load and provide ancillary services.

 

The following table summarizes the proposed projects currently included in the Repowering NRG program in Texas:

 

 

Cedar Bayou — In November 2006, NRG filed for a permit with the Texas Commission for Environmental Quality, or TCEQ, to repower single and combined cycle gas units consisting of up to 900 MW at NRG’s Cedar Bayou facility. The Company expects to receive permits and interconnection studies during the second half of 2007.

 

Limestone — NRG is proposing to repower an 800 MW pulverized baseload coal unit at the Company’s Limestone facility in central Texas, referred to as Limestone-3. Limestone-3 would be fueled primarily by PRB coal.

 

STP — NRG is proposing the addition of two nuclear reactors (Units 3 and 4) at the STP nuclear project. Commercial operations are proposed for late 2014 for Unit 3 and late 2015 for Unit 4. NRG has begun licensing

efforts and the Company anticipates filing a Combined Operating License Application with the NRC during the second half of 2007. NRG is proposing to use General Electric’s Advanced Boiling Water Reactor, or ABWR, technology, which is rated at approximately 1,350 MW per reactor.

 

Wind — The Company has 100-300 MW of wind projects under active development in Texas.

 

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. From 1994 through 2006, peak hourly demand in the ERCOT market grew at a compound annual rate of 3.0%, compared to a compound annual rate of growth of 2.1% in the United States for the same period. For 2006, hourly demand ranged from a low of 20,276 MW to a high of 63,056 MW. ERCOT has limited interconnections compared to other markets in the United States — currently limited to 856 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 can access the ERCOT electric power grid is allowed to sell power in the ERCOT market at unregulated rates.

 

The ERCOT market has experienced significant construction of new generation plants in recent years, with over 20,000 MW of mostly natural gas-fired combined cycle generation capacity added to the market in the first half of this decade. As of December 31, 2006, aggregate net generation capacity of approximately 76,964 MW existed in the ERCOT market, of which 72.1% was natural gas-fired. Approximately 20,616 MW, or 26.7%, was lower marginal cost generation capacity such as coal, lignite and nuclear plants. NRG’s coal and nuclear fuel baseload plants represent approximately 5,280 MW, or 26%, 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 at December 31, 2006, was 16.4%, forecast to drop to 11.4% 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 the Company expects reserve margins to decrease through 2010 primarily due to load growth. Many new projects have been announced that if materialized would begin to increase the reserve margin after 2010.

 

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 and all its natural gas-fired plants are located in the Houston zone. NRG’s Limestone plant is located in the North zone with STP located in the South 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 late 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 is focused on capturing the locational value of its plants that are located in or near load centers and inside chronic transmission constraints, in order to improve the economic rationale for repowering of those sites. NRG does this primarily through the advocacy of capacity market reforms. The Company has seen some success in these efforts with the start of the Locational Forward Reserve Markets, or LFRM, in the New England Power Pool, or NEPOOL, which, were effective October 1, 2006, and, in addition, with the start of transition capacity payments which were effective December 1, 2006, together acting as a prelude to the full implementation of the Forward Capacity Market, or FCM, which begins June 1, 2010. Further, on December 22, 2006, FERC approved a settlement regarding PJM’s reliability pricing model, or RPM, effective June 1, 2007.

 

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 2006, Middletown, Montville and Devon were covered by an RMR agreement.

Effective January 1, 2007, the region’s Devon plant is no longer covered by an RMR agreement but operates now on a merchant basis. On January 12, 2007, FERC approved the ISO-NE request to eliminate Peaking Unit Safe Harbor, or PUSH, bidding effective June 19, 2007. This decision adversely impacts the value of generation from the Norwalk Harbor plant. NRG anticipates that it will file for an RMR agreement for this plant to be effective upon the elimination of PUSH bidding. To that end, NRG has received a determination letter from ISO-NE that this plant is needed for reliability service.

 

Generation Facilities

 

As of December 31, 2006, NRG’s generation facilities in the Northeast region consisted of approximately 7,240 MW of generation capacity, including assets located in transmission constrained areas, such as in-city 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 generating 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 generating 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 585 MW from four baseload units. Units 1 and 2 produce up to 95 MW each and were put in service in 1950, and Units 3 and 4 produce approximately 195 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 generation capacity of 550 MW from two intermediate load units (Units 65 and 66) and 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 65 and 66 generate a net capacity of 85 MW each and were put in service between 1942 and 1954. Units 63 and 64 are inactive and were officially retired in May 2006. On November 30, 2006, NRG gave notice to the New York Department of Public Service of the Company’s intent to retire 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 by switching to low sulfur western coal and related projects for which NRG has already expended or committed significant capital.

 

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 steam electric units, Units 1 through 4 and one 15 MW combustion turbine, bringing total plant capacity to approximately 780 MW. Units 1 and 2 are each 80 MW of capacity and were placed in service in 1957 and 1959, respectively. Unit 3 is 165 MW of capacity and was placed in service in 1970, while Unit 4 is 440 MW of capacity and was placed in service in 1980. Units 3 and 4 are equipped with SNCR 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.

 

Repowering NRG — Northeast Region

 

The Repowering NRG program in the Northeast is focused on developing the region’s existing facilities, including using IGCC technology and coal in New York and Delaware, in addition to using combined cycle gas turbines and gas peakers (some with dual fuel capability on oil) in the region.

 

The following table summarizes the proposed projects currently included in the Repowering NRG program in the Northeast region:

 

 

Huntley — In December 2006, NRG won a conditional award in a competitive bid process with the New York Power Authority, or NYPA, to build a 600 MW IGCC plant at the Company’s 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.

 

Indian River — NRG also submitted a bid in December 2006 for the development of a similar IGCC plant at the Company’s Indian River facility in response to a Request for Proposals, or RFP, issued by Delmarva Power and Light. NRG’s bid proposed a 400 MW long term PPA for energy and capacity from the IGCC facility. The bid is currently under review and a formal award decision is scheduled to occur in the second quarter of 2007. If the bid is accepted, NRG expects to negotiate the terms of the PPA and obtain regulatory approval by the middle of 2007.

 

Connecticut — In December 2006, NRG submitted bids to repower a number of its existing facilities in Connecticut, in response to the State of Connecticut’s RFP process. The bids included separate proposals offering a total of approximately 1,000 MW of new capacity. The largest proposal includes a 630 MW combined cycle unit at the Company’s Montville site. The project covered by this proposal, if accepted, could be converted to an IGCC plant at a later date in response to any state energy and environmental policy objectives requiring baseload capacity that utilizes a plentiful domestic fuel source, such as coal. In addition, this conversion has the potential to bring material environmental benefits to the State of Connecticut, including the ability to capture and potentially sequester CO₂. NRG has also submitted bids for a new gas-fired peaking capacity at the Company’s Middletown and Devon sites.

 

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 security-constrained, financially firm, day-ahead unit commitment market. The second is a security-constrained, 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.

 

In addition to energy delivery, the ISOs manage secondary markets for installed capacity, ancillary services and financial transmission rights. All of the three Northeast ISOs have realized, however, that they are not capable of supporting needed investment in new generation without well designed capacity and ancillary service markets. NYISO’s capacity market was the first to receive approval of its proposed demand curve and locational capacity reforms (which are intended to better reflect locational values of capacity resources). ISO-NE and PJM are in the process of implementing their respective versions of reformed capacity markets, namely, a forward capacity market, or FCM, in ISO-NE, and a reliability pricing model, or RPM, proposal in PJM. ISO-NE has instituted a transitional payment for capacity starting December 1, 2006, which starts at a price of $3.05/kW-month and gradually rises to $4.10/kW-month through June 1, 2010, when the FCM market takes effect. In addition, ISO-NE instituted its LFRM market effective October 1, 2006 which provides a capacity payment for qualifying quick start units. NRG bid and was awarded 292 MW of LFRM capacity in the first auction which cleared at the capped rate of $14/kW-month. As indicated above, FERC approved a settlement of the PJM RPM market which will be effective June 1, 2007. For a further discussion, see Item 15 — Note 22 Regulatory Matters, to the Consolidated Financial Statements.

 

SOUTH CENTRAL

 

As of December 31, 2006, 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 two factors: (1) its position as a significant coal-fired generator in a market that is highly dependent on natural gas for power generation, and (2) its long-term contractual and historical service relationship with eleven rural cooperatives around Louisiana. NRG’s South Central region works with its cooperative customers to improve contract administration, to expand their and the Company’s customer bases on terms advantageous to all parties and, in some cases, to modify the terms of the Company’s contracts with respect to its current or new customers.

 

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, 2006 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, 2006, 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 low NO_x burners and overfire air. The Unit 1 generator has recently been rewound and was optimized with a modern turbine/exciter control system. Units 2 and 3 are planned for generator rewinds, turbine/exciter control replacements and

additional neural net systems in future years. These efficiency improvements are expected to cost approximately $30 million.

 

Repowering NRG — South Central Region

 

The region’s Repowering NRG strategy is focused on expanding generation capacity at the Company’s Big Cajun facilities, using coal and petcoke as fuel for the plants under best available control technology.

 

The following table summarizes the proposed projects currently included in the Repowering NRG program in the South Central region:

 

 

Big Cajun II — Unit 4 — The Company continues the development of a new 775 MW super critical coal-fired generating unit at its Big Cajun II facility. On April 28, 2006, NRG filed an application with the Louisiana Department of Environmental Quality, or LADEQ, to modify the existing permit to allow the Big Cajun II Unit 4 to utilize bituminous, in addition to sub-bituminous, coal. NRG has also entered into project development agreements with potential equity partners for certain ownership interests in Unit 4. However, NRG cannot predict the outcome of its application for the issuance of the modified permit at this time.

 

Big Cajun I — On May 26, 2006, NRG filed with LADEQ a request for an air permit for the addition of a 230 MW facility at the Company’s Big Cajun I facility. This proposed facility will have the ability to utilize petroleum coke, coal, or biomass as its fuel source.

 

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. Entergy performs the scheduling, reserve and reliability functions that are administered by the ISOs in certain other regions of the United States and Canada. Although the reliability functions performed are essentially the same, the primary differences between these markets lie in the physical delivery and price discovery mechanisms. In the South Central region, all power sales and purchases are consummated bilaterally between individual counterparties. Transacting counterparties are required to reserve and purchase transmission services from the relevant transmission owners at their FERC-approved tariff rates. Included with these transmission services are the reserve and ancillary costs.

 

As of December 31, 2006, NRG had long-term all-requirements contracts with eleven Louisiana distribution cooperatives with initial terms ranging from five to twenty-five years. The region had seven contracts 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 region’s contract load requirement.

 

During peak demand periods, NRG’s Big Cajun II assets are insufficient to serve the requirements of the customers under these contracts, and at such times NRG typically purchases power from other power producers in the region, frequently at higher prices than can be recovered under the Company’s contracts. As the loads of the region’s customers grow, the Company can expect this imbalance to worsen, unless NRG is successful in renegotiating the terms of these long-term contracts. 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 tolling agreements, which effectively reduce the need for spot market purchases.

 

WEST

 

NRG’s portfolio in the West region currently consists of the El Segundo Generating Station, the Encina Generating Station and 13 combustion turbines with total generation capacity of approximately 1,965 MW. On March 31, 2006, NRG purchased Dynegy Inc’s 50% ownership interest in WCP and became the sole owner of the WCP assets. In addition, NRG owns a 50% interest in the Saguaro power plant located in Nevada. 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 while protecting and potentially realizing 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 RFOs and eventually into a capacity market, and (2) using existing emission credits to permit new more efficient generating units at existing sites or siting plants at less valuable property and optimizing the value of the region’s coastal property for other purposes.

 

The Company’s Encina Station has sold all energy and capacity, 965 MW, in the aggregate, to SDG&E through 2009, on a tolling basis, and recovers its operating costs plus a capacity payment. 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. The San Diego Combustion Turbines, 190 MW, in the aggregate, are subject to an RMR agreement with the CAISO through calendar year 2007, on a tolling basis, and recover their costs plus a return of investment.

 

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 Pioneer, whose contract expires in 2007, with a negotiated renewal, 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, 2006 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. Dual fuel capability allows the units to use oil for emergency reliability backup only under a 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 has 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.

 

Repowering NRG — West Region

 

The region’s Repowering NRG strategy is focused on the construction of new capacity to meet increasing local requirements using natural gas at the Company’s existing facilities, as well as the development of potential wind projects through the Company’s wholly-owned subsidiary, Padoma Wind Power, LLC.

 

The following table summarizes the proposed projects currently included in the Repowering NRG program in the West region.

 

 

Long Beach — In November 2006, NRG was awarded a 260 MW PPA by Southern California Edison to repower Units 1-4 at the Company’s Long Beach Generating Station in Long Beach, California. The PPA term commences August 1, 2007 and continues for ten years.

 

El Segundo 1& 2 Repower Project  — NRG has permits from the California Energy Commission and Air District to construct a new gas-fired combined cycle plant at the Company’s El Segundo facility to replace the retired units at the site. NRG anticipates seeking amendments to these permits to substitute equipment that will not require the use of once-through sea water cooling. The reconfigured project is included in a load-serving entity’s RFO process which is scheduled to announce PPA contract awards for new capacity in early 2008.

 

In addition, the Company has submitted bids to one of the load-serving entities for two more projects in the West region. The Company expects to know the outcome of these bids sometime during the second half of 2007.

 

Market Framework

 

NRG’s assets in the West region consist primarily of older, higher heat rate, gas-fired plants in southern California. These plants, while older and less efficient than newer combined cycle plants, are 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. Currently, the El Segundo unit does not have an RMR agreement with CAISO, but has been designated as a local capacity resource in the Western Los Angeles area and has a tolling agreement for its full capacity with a local major utility for the period May 1, 2006 through April 30, 2008. All units at Encina and Cabrillo II have been designated as local capacity resources for the San Diego load pocket and were designated as RMR units for 2007. Per the RMR agreement, CAISO has an option to renew those units for RMR service into 2008. Encina has a tolling agreement for its full capacity with SDG&E for the period January 1, 2007 through December 31, 2009.

 

INTERNATIONAL

 

As of December 31, 2006, NRG, through certain foreign subsidiaries, had investments in power generation projects located in Australia, Germany and Brazil with approximately 1,235 MW of total generating 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, 2006 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, or Gladstone, and its associated 100% owned NRG Gladstone Operating Services to Transfield Services, an Australia-based provider of operations, maintenance, ownership and asset management services for a purchase price of approximately $189 million (AU$239 million) subject to customary purchase price adjustments, plus assumption of NRG’s share of Gladstone’s unconsolidated debt and cash of approximately $61 million (AU$77 million) and approximately $28 million (AU$35 million), respectively. After-tax cash proceeds are expected to be in excess of $185 million (AU$234 million). The sale is pending until NRG satisfies certain conditions, particularly the securing of certain consents and waivers from the other owners of the project, or agrees to complete the sale on alternative terms. NRG is seeking to close the transaction in 2007.

 

Germany — NRG’s interests in Germany include a 50% equity interest in MIBRAG, which mines approximately 20 million metric tons of lignite per year and owns 150 MW of electric generation capacity, and a 41.9% equity 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 89% of MIBRAG’s revenues are generated from lignite sales. MIBRAG’s generation capacity comprises three plants, 40% of whose output is used to power MIBRAG’s mining operations and the balance sold under contract to EnviaM, the local distribution utility. NRG, through its wholly-owned subsidiary Saale Energie Gesellschaft, or SEG, owns 400 MW of the Schkopau plant’s electric capacity which is sold under a long term contract to Vattenfall Europe Generation.

 

Brazil — NRG owns a 155 MW hydro-electric power plant located in the state of Mato Grosso, Brazil. NRG currently has a 99.2% interest in the plant.

 

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 1,230 megawatt thermal equivalents, or MWt. As of December 31, 2006, NRG Thermal provided steam heating to approximately 550 customers and chilled water to 95 customers in five different 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 the terms of the contract with the off-takers. In addition, NRG Thermal owns and operates three thermal projects that serve industrial and government customers with high-pressure steam and hot water. NRG Thermal also owns a 90 MW combustion turbine peaking generation facility and a 12 MW coal-fired cogeneration facility in Dover, Delaware as well as a 16 MW gas-fired project in

Harrisburg, Pennsylvania. Approximately 40% 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 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 the FERC’s rate regulation under Sections 205 and 206 of the FPA to the extent that sales are made pursuant to a state regulatory authority’s implementation of PURPA.

 

Public utilities under the FPA are required to obtain 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 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.

 

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 will be 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. The ERO will have the ability to assess financial penalties for non-compliance beginning in June 2007.

 

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 or FUCOs, 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; however, certain of NRG’s QFs currently interconnect into markets that may meet the qualifications for elimination of the PURPA purchase requirement. If the obligation to purchase from some or all of NRG’s QFs is terminated, NRG will need to find alternative purchasers for the output of these QFs once their current contracts expire. Such alternative purchases will be at prevailing market rates, which may not be as favorable as the terms of NRG’s PURPA sales arrangements under existing contracts and thus may diminish the value of the Company’s QFs. In addition, under FERC regulations for implementing EPAct of 2005, QFs not making sales pursuant to state-approved avoided cost rates will become subject to FERC’s ratemaking authority under the FPA and be required to obtain market rate authority in order to be allowed to sell power at market-based rates.

 

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 operating terms 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, any excess 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. PUCT also has jurisdiction over power generation companies with regard to the administration of nuclear decommissioning trusts, PUCT state-mandated capacity auctions, and the implementation of measures to mitigate undue market power that a power generation company may have and to remedy market power abuses in the ERCOT market and, indirectly, through oversight of ERCOT. 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 has 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 have been proposed, and it is not yet clear how they will operate in times of market stress 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 schedules, 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. Certain entity specific data disclosure provisions have been stayed by order of a Texas appellate court.

 

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 are expected to terminate upon the commencement of the Forward Capacity Market, as discussed below. The Devon RMR Agreement terminated on December 31, 2006.

 

On March 7, 2006, a broad group of New England market participants filed a settlement that 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 FCM, commencing June 1, 2010. The FCM established by the settlement will operate an annual descending clock forward capacity auction, normally three years in advance, and will serve as the principal mechanism by which ISO-NE will obtain its installed capacity requirement. For the Company’s Connecticut units subject to RMR agreements, any transition payment will be credited against the monthly availability payment for those units, resulting in no additional revenues for those units. NRG’s other New England generation units are eligible for the transition payments. On June 16, 2006, FERC issued an order accepting the settlement, which was reaffirmed on rehearing by order dated October 31, 2006. On December 28, 2006, the Attorneys General of the State of Connecticut and Commonwealth of Massachusetts filed an appeal of the FERC orders accepting the settlement with U.S. Court of Appeals for the D.C. Circuit. Interim capacity transition payments provided for under the FCM settlement commenced December 1, 2006, as scheduled.

 

On May 12, 2006, FERC issued an order accepting ISO-NE’s Ancillary Service Market Phase II package that includes a LFRM. This order was reaffirmed on rehearing on October 25, 2006. NRG’s quick-start units are well-suited to provide this service. For the eight-month winter period beginning October 1, 2006, the LFRM market for Connecticut cleared at the cap of $14/kW-month. NRG sold 292 MW in the LFRM auction and expects its participation in this market to positively contribute to revenues from the region.

 

On January 12, 2007, FERC accepted proposed amendments to ISO-NE’s market rules that eliminate the PUSH bidding mechanism effective June 19, 2007. The elimination of PUSH bidding will impact the Company’s Norwalk Harbor facility, and the Company anticipates seeking an RMR agreement for Norwalk Harbor Units 1 and 2.

 

New York — On December 22, 2006, the NYISO filed proposed tariff revisions that impose additional market power mitigation on the current owners of its divested generation units in New York City, including NRG’s Arthur Kill and Astoria facilities. The proposed mitigation effectively lowers the bid cap currently set forth in the NYISO tariff from $105/kW-year to $82/kW-year. This proposal could adversely impact capacity revenues from these units and NRG is contesting this filing before FERC.

 

On January 5, 2007, the Executive Committee of the New York State Reliability Council voted to change the Installed Reserve Margin, or IRM, from 18% to 16.5%. This change, which must be approved by FERC, will become effective for the May 2007 through April 2008 capacity year and will reduce the amount of capacity that must be purchased by load-serving entities.

 

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. The settlement agreement proposes to implement RPM, 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 anticipates conducting its first auction for the 2007-08 delivery years in April 2007 and implementing the RPM capacity market on June 1, 2007. The RPM settlement effectively accepts PJM’s August 31, 2006 filing with a number of revisions, as set forth in the settlement and December 22, 2006 order. NRG considers these market reforms to be a positive development for its assets in the region.

 

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 both the region’s existing operations by improving transmission access and competitive opportunities and the region’s development opportunities by administering the interconnection process. Certain issues regarding (i) the development of the base transmission plan; (ii) control over Entergy’s transmission models; and (iii) Entergy’s proposal to implement participant funding, are still being contested.

 

West Region

 

On December 1, 2006, NRG filed with FERC an extension of the existing RMR agreements for NRG’s Cabrillo Power I, LLC’s Encina facility, and Cabrillo Power II, LLC’s San Diego Jets facility for 2007, and to continue the existing rate effective January 1, 2007. On January 24, 2007, FERC accepted the Cabrillo I filing. On January 30, 2007, FERC accepted the Cabrillo II filing, subject to refund, in response to protests filed by the CPUC and CAISO, and established settlement procedures. NRG has negotiated a three-year bilateral arrangement with SDG&E for Encina that insulates Encina from any revenue impact associated with the RMR agreement.

 

On September 21, 2006, FERC conditionally accepted the CAISO’s Market Redesign and Technology Upgrade, or MRTU, proposal which is currently scheduled to go in effect in January 31, 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 requested rehearing, which remains pending.

 

On July 20, 2006, the CPUC issued its order towards establishing a standard Resource Adequacy Capacity Product that followed its decision to impose local capacity requirements, which took effect January 1, 2007. On the same date, the CPUC issued its order on long-term resource procurement that requires SCE to procure at least 1,500 MW.

 

In November 2006, NRG was awarded a 260 MW PPA by Southern California Edison to repower Units 1-4 at the Company’s Long Beach Generating Station in Long Beach, California. On February 22, 2007, an intervener sought rehearing of the CPUC approval of the agreement and is contesting the PPA at FERC.

 

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 emissions control 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 US 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. Texas and Louisiana will adopt the CAMR federal implementation plan, or FIP, when it is finalized by USEPA. Certain states in which NRG operates coal plants in NRG’s Northeast region such as Delaware, Massachusetts and New York have proposed or adopted state implementation plans in lieu of the CAMR FIP. Provisions for mercury monitoring and mitigation technologies are included in the budget and environmental capital expenditures for NRG’s coal plants.

 

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 and caps 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. In parallel: (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 the 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 must 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 beyond those required by CAIR.

 

Increased public concern and mounting political pressure may result in federal requirements to reduce or mitigate the effects of GHG. NRG’s generating portfolio includes coal-, oil- and gas-fired plants, which emit CO₂, a GHG, and will likely be subject to proposed regulation which could affect NRG’s costs of operation. NRG is taking steps now to mitigate any potential adverse impacts, including investments in non-fossil generation and investments in generation technologies that will more easily allow the company to manage and control CO₂ emissions.

 

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, Prevention of Significant Deterioration, or PSD, requirements. EPA 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 EPA about resolving the claims. See the South Central regional below for a further discussion.

 

Water — In July 2004, USEPA published rules governing cooling water intake structures at existing power facilities commonly referred to as the Phase II 316(b) rules. The 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. US EPA 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 EPA for reconsideration and restricted EPA’s ability to allow generators to substitute mitigation for aquatic species losses through habitat restoration or other measures. The Phase II 316(b) regulation affects a number of NRG’s plants, specifically those with once-through cooling systems. While NRG has conducted a number of the requisite studies, until all the needed studies throughout the Company’s fleet have been completed, consultations on the results have occurred with USEPA or its delegated state or regional agencies, and EPA concludes its reconsideration of the 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 such as STP. Consistent with the Act, owners of nuclear plants, including NRG and the other 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 being 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, Texas Genco LP and the other 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 US are subject to a cap-and-trade program governing NO_x emissions during the ozone season, typically from May 1 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 has been allocated NO_x emission allowances. NRG currently estimates that the portfolio total is currently 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 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 allowances could have a material adverse effect on NRG’s operations.

 

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 have slipped although additional SO₂ and NO_x reductions are still in

discussion. 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, seven northeastern states entered into a Memorandum of Understanding, or MOU, to create a Regional Greenhouse Gas initiative to establish a cap-and-trade greenhouse gas program for electric generators, referred to as RGGI. Maryland and Massachusetts have since announced their intent to join. In August 2006, the states participating in RGGI released a model rule which addresses program elements including timelines, monitoring, the use of offsets, and allowance trading. The program begins in 2009. Individual states in which NRG operates including Connecticut, Delaware, Massachusetts and New York must promulgate state rules, which can be based on the model rule, and in addition, address allowance allocations/auctions, treatment of unallocated allowances and leakage. New York issued a pre-proposal version in December 2006 which, among other things, proposes to increase MOU suggested set aside of allowances from 25% to 100% and that these allowances be auctioned. New York is accepting comments on the pre-proposal and expects to have a final rule later in 2007. Connecticut, Delaware and Massachusetts plan to develop rules in 2007. NRG has proposed clean coal IGCC projects that are carbon capture ready to meet future generation demands in both New York and Delaware and also, potentially, Connecticut. NRG continues to actively participate in state and regional RGGI proceedings.

 

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 our 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 submitted to the MADEP in December 2006.

 

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 cap applies from January 1, 2006, while a rate requirement will apply in 2008. It is expected that Somerset will meet the cap from 2006 through 2007 and purchase offsets after that period. Massachusetts announced in January 2006 that they will join the other Northeast states in RGGI.

 

New York — 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 a compliance schedule. In 2006, NRG accrued amounts payable to NYSDEC of $0.2 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 current plan to install controls at the Company’s Indian River facility, while on an accelerated basis, is unable to meet certain deadlines for SO₂ and NO_x controls in Phase 1, taking into account the time required, as a practical matter, to design, install and commission the necessary equipment. NRG and the owners of all other subject facilities in the state filed a challenge to Reg 1146 with the Environmental Appeals Board on December 6, 2006. In addition, NRG also filed a protective appeal with the Delaware Superior Court on December 29, 2006. NRG is unable to predict the outcome of the proceedings at this time, but failure to obtain relief may result in a material impact to the Company’s Indian River facility.

 

On January 5, 2005, DNREC initiated a rule making to incorporate USEPA’s NSR reforms within Delaware’s Regulation 25. Delaware was required to revise the state’s current rules and demonstrate such revisions are equivalent to, or more stringent than, the USEPA’s revised rules by January 2006, which Delaware did not meet. The state is considering a facility emissions limit that would cap all NSR applicable pollutants. The results of the rule making, expected in 2007, will impact Indian River and Dover facilities.

 

West Region

 

NRG’s El Segundo Generating Station is regulated by the South Coast Air Quality Management District, or SCAQMD. Before the station’s retirement as of January 1, 2005, the Long Beach Generating Station was also regulated by SCAQMD. SCAQMD approved amendments to its Regional Clean Air Incentives Market, or RECLAIM, NO_x regulations on January 7, 2005. RECLAIM is a regional emission-trading program targeting NO_x reductions to achieve state and federal ambient air quality standards for ozone. Among other changes, the amendments reduce the NO_x RECLAIM Trading Credit, or RTC, holdings of El Segundo Power, LLC and Long Beach Generation LLC facilities by certain amounts. Notwithstanding these amendments, retained RTCs are expected to be sufficient to operate El Segundo Units 3 and 4 as high as 100% capacity factor for the life of those units.

 

On September 27, 2006, Governor Arnold Schwarzenegger signed Assembly Bill 32 — California Global Warming Solutions Act of 2006 and Senate Bill 1368 — Electricity: Emissions of Greenhouse Gases. Assembly Bill 32, or AB 32, requires the California Air Resources Board, or CARB, to develop a greenhouse gas reduction program to reduce emissions to 1990 levels by 2020, a reduction of approximately 25%. The reductions will be phased in beginning 2012 pursuant to regulations to be adopted by 2011. The financial impact to NRG will depend on final regulations. In addition, the governor also signed Senate Bill 1368, or SB 1368, which prohibits utilities from entering into contracts of five years or more for any baseload generation exceeding a 60% capacity factor unless the contracting facility complies with a greenhouse gas performance standard no higher than the rate of GHG emissions for a combined cycle natural gas baseload power plant. NRG’s plants and development projects in California are unaffected by SB 1368 because they either meet the combined cycle standard or they do not exceed the 60% capacity factor and/or five year contract term thresholds.

 

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 review 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 DC 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 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. NRG is working with the DNREC, through the Voluntary Clean-up Program to investigate the site. The Company is unable to predict the exact impact at this time.

 

Further details regarding our Domestic Site Remediation obligations can be found at 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, which is an international treaty related to greenhouse gas emissions enacted on February 16, 2005, and 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 effect the Company’s international operations.

 

MIBRAG/Schkopau, Germany — CO₂ emissions trading began in Germany in 2005, pursuant to European Union obligations under the Kyoto Protocol. Trading rules and emissions allocations for the second emissions trading period (2008 through 2012) have not yet been established by the regulators, therefore the impact of the new rules on NRG’s German business cannot be predicted at this time. Changes to the German Emission Control Directive have specified lower NO_x emission limits for plants firing conventional fuels and co-firing waste products. The new regulations required the Mumsdorf and Deuben Power stations to install additional controls to reduce NO_x emissions in 2006. These plant modifications have been successfully completed. The regulations of the revised European Union’s Groundwater Directive and Mine Wastewater Management Directive are now in effect and MIBRAG sees no negative effects on its mining operations or economics.

 

Available Information

 

NRG’s annual reports on Form 10-K, quarterly reports on Form10-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 we 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 materially 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 2012, 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 NRG’s 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, as amended, 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’s Repowering NRG program is subject to financing, construction, and operational risks that could adversely impact NRG’s financial performance

 

While NRG currently intends to develop and finance the more capital intensive, solid fuel-fired projects included in the Repowering NRG program on a non-recourse or limited recourse basis through separate project financed entities, and intends to seek additional investments in most of these projects from third parties, NRG anticipates that it will need to make significant equity investments in these projects. NRG may also decide to develop and finance some of the projects, such as smaller gas-fired and renewable projects, using corporate financial resources rather than non-recourse debt, which could subject NRG to significant capital expenditure requirements and to risks inherent in the development and construction of new generation facilities. In addition to providing some or all of the equity required to develop and build the proposed projects, NRG’s ability to finance these projects on a non-recourse basis is contingent upon a number of factors, including the terms of the engineering, procurement and construction contracts, construction costs, power purchase agreements 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 projects or should the credit rating agencies attribute a material amount of the project finance debt to NRG’s credit, the financing of the Repowering NRG projects could have a negative impact on the credit ratings of NRG. In addition, there are risks inherent in the development and construction of new generation facilities. Further, certain of the Repowerng NRG projects incorporate advanced equipment and technologies with only a modest amount of operating history in the proposed configurations. There also exists the possibility of cost overruns, schedule delays and performance risks during the construction phase, as well as the possibility of operational and contractual issues during the commercial operational life of these new generation facilities that could adversely impact NRG’s financial performance.

 

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

 

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 own 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 1,100 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 our plants. If NRG fails 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. In particular, several states in which NRG operates have proposed or are in the process of proposing requirements to control emissions of NOx, SO₂, and mercury from electric generating units that are more stringent than federal regulations. In Delaware, NRG and others have appealed portions of such a regulation for the control of multiple pollutants to both the Environmental Appeals Board and Delaware Superior Court, based not on the required level of emissions reductions, but on the timing for achievement of those reductions by 2009. We are unable to predict the outcome of these appeals.

 

There is a growing consensus in the U.S. and globally that greenhouse gases, or GHG, emissions are linked to global climate change. States in the Northeast under RGGI and California under AB32 are expected to propose rules to stabilize and reduce GHG in the near future. Increased public concern and mounting political pressure may result in more regional and/or federal requirements to reduce or mitigate the effects of GHG. NRG’s U.S. generating portfolio includes coal-, oil- and gas-fired plants that are projected to emit approximately 70 million tons of CO₂, a GHG, for 2007. The Company’s facilities in New York and California will be subject to regulation under RGGI and AB32, respectively. It is likely that the Company’s U.S. plants would also be subject to regulation under any new GHG legislation introduced at the state, regional or national level. While NRG plans to address the risks of such GHG regulations through CO₂ offsets, by supporting CO₂ mitigation research, and by pursuing CO₂ sequestration capable facilities, technologies such as nuclear and wind that do not emit GHG, and highly efficient fossil fuel projects, the costs of complying with potential GHG regulations may be substantial and may have a significant impact on NRG’s operations, cash flow and financial position. The actual impact of any state, regional or federal GHG regulations on NRG will depend on a number of factors including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the degree to which the forward market prices on the cost of GHG regulation, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas prices.

 

A recent court ruling on the appeal of the USEPA Phase II 316(b) regulation has created uncertainty for power plants that use once-through cooling water. Specifically, the ruling remanded certain provisions back to the USEPA for reconsideration and prohibits certain mitigation technologies, including restoration. In light of this ruling, NRG anticipates that it will not be able to rely on restoration and cost-benefit adjustment at some of its facilities in the West region. In addition, the ruling has created some uncertainty with respect to approximately 17% of the Company’s other generating units that do not have cooling towers. NRG continues to complete and analyze fish studies and design solutions which will meet the Phase II 316(b) regulation when finalized for all of its facilities that use once-through cooling. NRG is closely following progress on the final rule, although it is not possible to quantify the impact of the revisions at this time.

 

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 the Company’s 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.

 

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

 

As of December 31, 2006, approximately 55% of NRG’s employees at its U.S. generation plants would have been 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.

 

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. 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, 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 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.

 

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.

 

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.

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 2006 Annual Report on Form 10-K and the following: