10-K 1 a201110-k.htm FORM 10-K 2011 10-K
 
 
 
 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
x
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year ended December 31, 2011.
 
 
 
o
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition period from                      to                       .
Commission file No. 001-15891
     NRG Energy, Inc.
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of incorporation or organization)
 
41-1724239
(I.R.S. Employer Identification No.)
 
 
 
211 Carnegie Center Princeton, New Jersey
(Address of principal executive offices)
 
08540
(Zip Code)
(609) 524-4500
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
 
Name of Exchange on Which Registered
Common Stock, par value $0.01
 
New York Stock Exchange
     Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes x    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 x
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 x    No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes x    No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer x
 
Accelerated filer o
 
Non-accelerated filer o
 
Smaller reporting company o
 
 
 
 
(Do not check if a smaller reporting company)
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes o    No x
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 $5,509,659,060 based on the closing sale price of $24.58 as reported on the New York Stock Exchange.
Indicate the number of shares outstanding of each of the registrant's classes of common stock as of the latest practicable date.
Class
 
Outstanding at February 22, 2012
Common Stock, par value $0.01 per share
 
227,685,120
Documents Incorporated by Reference:
Portions of the registrants definitive Proxy Statement relating to its 2012 Annual Meeting of Stockholders
are incorporated by reference into Part III of this Annual Report on Form 10-K
 
 
 
 
 




TABLE OF CONTENTS
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

2


Glossary of Terms
        When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
2011 Form 10-K
 
NRG's Annual Report on Form 10-K for the year ended December 31, 2011
2011 Revolving Credit Facility
 
The Company's $2.3 billion revolving credit facility due 2016, a component of the 2011 Senior Credit Facility
2011 Senior Credit Facility
 
As of July 1, 2011, NRG's new senior secured facility, comprised of a $1.6 billion term loan facility and a $2.3 billion revolving credit facility, which replaces the Senior Credit Facility
2011 Term Loan Facility
 
The Company's $1.6 billion term loan facility due 2018, a component of the 2011 Senior Credit Facility
316(b) Rule
 
A section of the Clean Water Act regulating cooling water intake structures
AB32
 
Assembly Bill 32 — California Global Warming Solutions Act of 2006
ASC
 
The FASB Accounting Standards Codification, which the FASB established as the source of authoritative U.S. GAAP
ASR Agreement
 
Accelerated Share Repurchase Agreement
ASU
 
Accounting Standards Updates – updates to the ASC
Baseload Capacity
 
Coal and nuclear electric power generation capacity normally expected to serve loads on an around-the-clock basis throughout the calendar year
BACT
 
Best Available Control Technology
BTU
 
British Thermal Unit
CAA
 
Clean Air Act
CAIR
 
Clean Air Interstate Rule
CAISO
 
California Independent System Operator
Capital Allocation Plan
 
Share repurchase program
Capital Allocation Program
 
NRG's plan of allocating capital between debt reduction, reinvestment in the business, and share repurchases through the Capital Allocation Plan
CDWR
 
California Department of Water Resources
C&I
 
Commercial, industrial and governmental/institutional
CFTC
 
U.S. Commodity Futures Trading Commission
CO2
 
Carbon dioxide
CPS
 
CPS Energy
CS
 
Credit Suisse Group
CSAPR
 
Cross-State Air Pollution Rule
CSF I
 
NRG Common Stock Finance I LLC
CSF II
 
NRG Common Stock Finance II LLC
CSF Debt
 
CSF I and CSF II issued notes and preferred interest, individually referred to as CSF I Debt and CSF II Debt
CSRA
 
Credit Sleeve Reimbursement Agreement with Merrill Lynch in connection with acquisition of Reliant Energy, as hereinafter defined
Distributed Solar
 
Solar power projects, typically less than 20 MW in size, that primarily sell power produced to customers for usage on site, or are interconnected to sell power into the local distribution grid

DNREC
 
Delaware Department of Natural Resources and Environmental Control
Energy Plus
 
Energy Plus Holdings LLC
EPC
 
Engineering, Procurement and Construction
ERCOT
 
Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
ESPP
 
Employee Stock Purchase Plan
EWG
 
Exempt Wholesale Generator
Exchange Act
 
The Securities Exchange Act of 1934, as amended

3


Expected Baseload Generation
 
The net baseload generation limited by economic factors (relationship between cost of generation and market price) and reliability factors (scheduled and unplanned outages)
FCM
 
Forward Capacity Market
FERC
 
Federal Energy Regulatory Commission
FFB
 
Federal Financing Bank
FPA
 
Federal Power Act
Fresh Start
 
Reporting requirements as defined by ASC-852, Reorganizations
Funded Letter of Credit Facility
 
Prior to July 1, 2011, NRG's $1.3 billion term loan-backed fully funded senior secured letter of credit facility, of which $500 million would have matured on February 1, 2013, and $800 million would have matured on August 31, 2015, and was a component of NRG's Senior Credit Facility. On July 1, 2011, NRG replaced its Senior Credit Facility, including the Funded Letter of Credit Facility, with the 2011 Senior Credit Facility.
GenOn
 
GenOn Energy, Inc. (formerly RRI Energy, Inc., formerly Reliant Energy, Inc.)
GHG
 
Greenhouse Gases
Green Mountain Energy
 
Green Mountain Energy Company
GWh
 
Gigawatt hour
Heat Rate
 
A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWh's generated. Heat rates can be expressed as either gross or net heat rates, depending whether the electricity output measured is gross or net generation and is generally expressed as BTU per net kWh
ISO
 
Independent System Operator, also referred to as Regional Transmission Organizations, or RTO
ISO-NE
 
ISO New England Inc.
kWh
 
Kilowatt-hours
LFRM
 
Locational Forward Reserve Market
LIBOR
 
London Inter-Bank Offer Rate
LTIP
 
Long-Term Incentive Plan
Mass
 
Residential and small business
MATS
 
Mercury and Air Toxics Standards
Merit Order
 
A term used for the ranking of power stations in order of ascending marginal cost
MIBRAG
 
Mitteldeutsche Braunkohlengesellschaft mbH
MMBtu
 
Million British Thermal Units
MW
 
Megawatts
MWh
 
Saleable megawatt hours net of internal/parasitic load megawatt-hours
MWt
 
Megawatts Thermal Equivalent
NAAQS
 
National Ambient Air Quality Standards
Net Baseload Capacity
 
Nominal summer net megawatt capacity of power generation adjusted for ownership and parasitic load, and excluding capacity from mothballed units as of December 31, 2010
Net Capacity Factor
 
The net amount of electricity that a generating unit produces over a period of time divided by the net amount of electricity it could have produced if it had run at full power over that time period. The net amount of electricity produced is the total amount of electricity generated minus the amount of electricity used during generation.
Net Exposure
 
Counterparty credit exposure to NRG, net of collateral
Net Generation
 
The net amount of electricity produced, expressed in kWhs or MWhs, that is the total amount of electricity generated (gross) minus the amount of electricity used during generation.
NINA
 
Nuclear Innovation North America LLC
NOx
 
Nitrogen oxide
NOL
 
Net Operating Loss
NPNS
 
Normal Purchase Normal Sale
NRC
 
U.S. Nuclear Regulatory Commission
NSPS
 
New Source Performance Standards

4


NSR
 
New Source Review
NYISO
 
New York Independent System Operator
OCI
 
Other comprehensive income
Phase II 316(b) Rule
 
A section of the Clean Water Act regulating cooling water intake structures
PJM
 
PJM Interconnection, LLC
PJM market
 
The wholesale and retail electric market operated by PJM primarily in all or parts of Delaware, the District of Columbia, Illinois, Maryland, New Jersey, Ohio, Pennsylvania, Virginia and West Virginia
PM 2.5
 
Particulate matter particles with a diameter of 2.5 micrometers or less
PPA
 
Power Purchase Agreement
PSD
 
Prevention of Significant Deterioration
PUCT
 
Public Utility Commission of Texas
PUHCA of 2005
 
Public Utility Holding Company Act of 2005
PURPA
 
Public Utility Regulatory Policy Act
QF
 
Qualifying Facility under PURPA
QSE
 
Qualified Scheduling Entities
Reliant Energy
 
NRG's retail business in Texas purchased on May 1, 2009, from Reliant Energy, Inc. which is now known as GenOn Energy, Inc., or GenOn
Repowering
 
Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility, not only to achieve a substantial emissions reduction, but also to increase facility capacity, and improve system efficiency
REP
 
Retail Electric Provider
RERH
 
RERH Holding, LLC and its subsidiaries
Revolving Credit Facility
 
Prior to July 1, 2011, NRG's $925 million senior secured revolving credit facility, which would have matured on August 31, 2015, and was a component of NRG's Senior Credit Facility. On July 1, 2011, NRG replaced the Senior Credit Facility, including the Revolving Credit Facility, with the 2011 Senior Credit Facility.
RGGI
 
Regional Greenhouse Gas Initiative
RMR
 
Reliability Must-Run
Schkopau
 
Kraftwerk Schkopau Betriebsgesellschaft mbH, an entity in which NRG has a 41.9% interest
SEC
 
United States Securities and Exchange Commission
Securities Act
 
The Securities Act of 1933, as amended
Senior Credit Facility
 
Prior to July 1, 2011, NRG's senior secured facility was comprised of a Term Loan Facility, an $925 million Revolving Credit Facility and a $1.3 billion Funded Letter of Credit Facility. On July 1, 2011, NRG replaced the Senior Credit Facility with the 2011 Senior Credit Facility.
SIFMA
 
Securities Industry and Financial Markets Association
Senior Notes
 
The Company's $6.1 billion outstanding unsecured senior notes consisting of $1.1 billion of 7.375% senior notes due 2017, $1.2 billion of 7.625% senior notes due 2018, $700 million of 8.5% senior notes due 2019, $800 million of 7.625% senior notes due 2019, $1.1 billion of 8.25% senior notes due 2020, and $1.2 billion of 7.875% senior notes due 2021
SERC
 
Southeastern Electric Reliability Council/Entergy
SO2
 
Sulfur dioxide
STP
 
South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% Interest
STPNOC
 
South Texas Project Nuclear Operating Company
TANE
 
Toshiba America Nuclear Energy Corporation
TANE Facility
 
NINA's $500 million credit facility with TANE
TEPCO
 
The Tokyo Electric Power Company of Japan, Inc.

5


Term Loan Facility
 
Prior to July 1, 2011, a senior first priority secured term loan, of which approximately $608 million would have matured on February 1, 2013, and $990 million would have matured on August 31, 2015, and was a component of NRG's Senior Credit Facility. On July 1, 2011, NRG replaced its Senior Credit Facility, including the Term Loan Facility, with the 2011 Senior Credit Facility.
Texas Genco
 
Texas Genco LLC, now referred to as the Company's Texas Region
Tonnes
 
Metric tonnes, which are units of mass or weight in the metric system each equal to 2,205lbs and are the global measurement for GHG
TWh
 
Terawatt hour
U.S.
 
United States of America
U.S. DOE
 
United States Department of Energy
U.S. EPA
 
United States Environmental Protection Agency
U.S. GAAP
 
Accounting principles generally accepted in the United States
Utility Scale Solar
 
Solar power projects, typically 20 MW or greater in size, that are interconnected into the transmission or distribution grid to sell power at a wholesale level

VaR
 
Value at Risk
VIE
 
Variable Interest Entity
WCP
 
WCP (Generation) Holdings, Inc.


6


PART I

Item 1 — Business

General

NRG Energy, Inc., or NRG or the Company, is an integrated wholesale power generation and retail electricity company that aspires to be a leader in the way the industry and consumers think about, use, produce and deliver energy and energy services in major competitive power markets in the United States. First, NRG is a wholesale power generator engaged in the ownership and operation of power generation facilities; the trading of energy, capacity and related products; and the transacting in and trading of fuel and transportation services. Second, NRG is a retail electricity company engaged in the supply of electricity, energy services, and cleaner energy products to retail electricity customers in deregulated markets through Reliant Energy, Green Mountain Energy, and Energy Plus (collectively, the Retail Businesses). Finally, NRG is focused on the deployment and commercialization of potential disruptive technologies, like electric vehicles, Distributed Solar and smart meter technology, which have the potential to change the nature of the power supply industry.
 
Wholesale Power Generation

NRG's generation facilities consist of intermittent, baseload, intermediate and peaking power generation facilities in the United States and two international locations. The sale of capacity and power from baseload generation facilities accounts for a majority of the Company's generation revenues. In addition, NRG's generation portfolio provides the Company with opportunities to capture additional revenues by selling power during periods of peak demand, offering capacity or similar products, and providing ancillary services to support system reliability.

Retail
 
NRG's Retail Businesses arrange for the transmission and delivery of energy-related products to customers, bill customers, collect payments for products sold, and maintain call centers to provide customer service. The Retail Businesses sell products that range from system power to bundled products, which combine system power with protection products, energy efficiency and renewable energy solutions, or other value added products and services, including customer rewards offered through exclusive loyalty and affinity program partnerships. Based on metered locations, as of December 31, 2011, NRG's Retail Businesses combined to serve approximately 2.1 million residential, small business, commercial and industrial customers.

Alternative Energy
 
NRG's investment in and development of new technologies is focused where the Company believes the benefits of such investments represent significant commercial opportunities and create a comparative advantage for the Company. The development and investment initiatives are primarily focused in the areas of Distributed Solar, solar thermal and solar photovoltaic, and also include other low or no Greenhouse Gases, or GHG, emitting energy generating sources, such as the fueling infrastructure for electric vehicle, or EV, ecosystems.

NRG's Business Strategy

The Company believes that the American energy industry is going to be increasingly impacted by the long-term societal trend towards sustainability which is both generational and irreversible. Moreover, the information technology-driven revolution which has enabled greater and easier personal choice in other sectors of the consumer economy will do the same in the American energy sector over the years to come. As a result, energy consumers will have increasing personal control over whom they buy their energy from, how that energy is generated and used and what environmental impact these individual choices will have. The Company's initiatives in this area of future growth are focused on: (i) renewables, with a concentration in solar development; (ii) electric vehicle ecosystems; (iii) customer-facing energy products and services including smart grid services, nationwide retail green electricity, unique retail sales channels involving loyalty and affinity programs and custom design; and (iv) construction of other forms of on-site clean power generation. The Company's advances in each of these areas are driven by select acquisitions, joint ventures, and investments that are more fully described in Item 1, Business - New and On-going Company Initiatives and Development Projects.


7


The Company's core business is focused on: (i) excellence in safety and operating performance of its existing assets; (ii) serving the energy needs of end-use residential, commercial and industrial customers in the Company's core markets with a retail energy product that is differentiated either by premium service (Reliant), sustainability (Green Mountain Energy) or loyalty/affinity programs (Energy Plus); (iii) optimal hedging of baseload generation and retail load operations, while retaining optionality on the Company's peaking facilities; (iv) repowering of power generation assets at premium sites; (v) investment in, and deployment of, alternative energy technologies both in its wholesale and, particularly, in and around its retail businesses and their customers; (vi) pursuing selective acquisitions, joint ventures, divestitures and investments; and (vii) engaging in a proactive capital allocation plan focused on achieving the regular return of and on stockholder capital within the dictates of prudent balance sheet management.

In summary, NRG's business strategy is intended to maximize stockholder value through the production and sale of safe, reliable and affordable power to its customers in the markets served by the Company, while aggressively positioning the Company to meet the market's increasing demand for sustainable and low carbon energy solutions. This strategy is designed to enhance the Company's core business of competitive power generation and mitigate the risk of declining power prices. The Company expects to become a leading provider of sustainable energy solutions that promotes national energy security, while utilizing the Company's retail business to complement and advance both initiatives.

Competition

NRG competes in wholesale power generation, deregulated retail energy services and in the development of renewable and conventional energy resources.

Wholesale Power Generation

Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. NRG competes on the basis of the location of its plants and ownership of portfolios of plants in various regions, which increases the stability and reliability of its energy supply. Wholesale power generation is a regional business that is currently highly fragmented and diverse in terms of industry structure. As such, there is a wide variation in terms of the capabilities, resources, nature and identity of the companies NRG competes with depending on the market. Competitors include regulated utilities, other independent power producers, and power marketers or trading companies, including those owned by financial institutions, municipalities and cooperatives.

Retail

The restructured electricity markets across the nation provide an intensely competitive landscape for energy providers to sell products and services to all customer segments (residential, small and mid-market businesses, governments and other public institutions). The markets in which we compete include, but are not limited to: Connecticut, Delaware, the District of Columbia, Illinois, Maryland, Massachusetts, New Jersey, New York, Pennsylvania, Ohio and Texas. The Electric Reliability Council of Texas, or ERCOT, is our primary market and constitutes both the highest number of customers and a substantial concentration of NRG's gross profits.

Retail customers make purchase decisions based on a variety of factors, including price, customer service, brand image, product choices, bundles or value-added features. Customers purchase products through a variety of sales channels including direct sales force, call centers, websites, brokers and brick-and-mortar stores. The Retail Businesses compete with national and international companies that operate in multiple geographic areas, as well as numerous companies that are regional or local in nature. Significant competitors in the markets in which we compete include Constellation, Direct Energy, GDF Suez and Energy Future Holdings (d/b/a TXU Energy), and other competitors, typically incumbent retail electric providers, which have the advantage of long-standing relationships with customers.

Development

NRG may submit bids to develop generation resources, predominantly in response to requests for proposals, or RFPs, for new conventional or renewable generation and/or generating capacity.  Bids are solicited by regulated utilities or electric system operators, often to comply with mandated renewable portfolio standards or to achieve an improved reserve margin, which is a measure of a utility's available electric power capacity over and above the electric power capacity needed to meet normal peak demand levels. NRG competes against other power plant developers and manufacturers of solar panel assemblies. The number and type of competitors vary based on the location, generation type, project size and counterparty specified in the RFP. Bids are awarded based on price, location of existing generation, prior experience developing generation resources similar to that specified in the RFP, and creditworthiness.

8



Competitive Strengths

Conventional Wholesale Power Generation

NRG has one of the largest and most diversified power generation portfolios in the United States, with approximately 23,585 MW of fossil fuel and nuclear generation capacity in 189 active generating units at 45 plants as of December 31, 2011. In addition, the Company has a 550 MW combined cycle gas plant under construction. The Company's power generation assets are diversified by fuel-type, dispatch level and region, which helps mitigate the risks associated with fuel price volatility and market demand cycles.
NRG's U.S. baseload and intermediate facilities provide the Company with a significant source of cash flow, while its peaking facilities provide NRG with opportunities to capture upside potential that can arise from time to time during periods of high demand.
Many of NRG's generation assets are located within densely populated areas that tend to have more robust wholesale pricing as a result of relatively favorable local supply-demand balance. NRG has generation assets located within Houston, New York City, southwestern Connecticut, and the Los Angeles and San Diego load basins. These facilities are often ideally situated for repowering or the addition of new capacity, because their location and existing infrastructure give them significant advantages over undeveloped sites.

Retail

Through its Retail Businesses, NRG served 2.1 million customers in 2011, delivering over 57 TWhs, making it one of the largest retail energy providers in the United States. NRG's Retail Businesses offer a broad range of services and value propositions that enable it to attract, retain, and increase the value of our residential, small business and commercial customer relationships. With the largest market share in ERCOT based on volume sales, Reliant Energy is recognized by its exemplary customer service (ranked the highest in customer satisfaction by the Public Utility Commission of Texas, or PUCT, in 2011) as well as its innovative technology product offerings and home energy services. As one of the nation's leading retail providers of clean energy, Green Mountain Energy is widely recognized as a pioneer in the competitive retail energy market and provides customers an environmentally friendly alternative to their energy supply requirements. Acquired in 2011, Energy Plus primarily enrolls and retains electricity and natural gas customers through exclusive marketing arrangements with leading loyalty program providers and affinity group associations. Through these Retail Businesses, NRG is able to provide its customers a broad range of energy services and products, including system power, distributed generation, solar and wind products, carbon management and specialty services, and smart grid services. The breadth and scope of these Retail Businesses also create opportunities for delivering value enhancing energy solutions to customers on a national level.
Solar and Other Alternative Energy Technologies

NRG is one of the largest solar power developers in the U.S., having demonstrated the ability to develop, construct and finance a full range of solar energy solutions for utilities, schools, municipalities, commercial and residential market segments. The Company has 545 MW of renewable generation capacity which consists of ownership interests in four wind farms, three Utility Scale Solar facilities, and approximately 30 MW of Distributed Solar as of December 31, 2011. In addition, the Company has 860 MW of solar capacity under construction: 855 MW at six Utility Scale Solar facilities and 5 MW of Distributed Solar. Through its relationships with solar equipment providers, NRG is able to deploy diverse solar technologies in both the utility and distributed generating scale projects that creates value for the Company while meeting the clean renewable energy requirements of its customers NRG is responding to the growing consumer demand for cleaner transportation solutions by building the first privately funded EV charging infrastructure network in select major metropolitan areas.


9


The map below shows the locations of NRG's U.S. power generation facilities as of December 31, 2011, (excluding Distributed Solar), both operating and under construction, as well as the states where NRG operates its Retail Businesses:




10


The following table summarizes NRG's global generation portfolio as of December 31, 2011, by operating segment, which includes 47 fossil fuel plants, three Utility Scale Solar facilities and four wind farms, as well as Distributed Solar facilities. Also included are one natural gas plant, six Utility Scale Solar facilities and additional Distributed Solar facilities currently under construction. All Utility Scale Solar and Distributed Solar facilities are described in megawatts on an alternating current, or AC, basis:
 
 
Fossil Fuel, Nuclear, and Renewable
 
 
(In MW)
Generation Type
 
Texas
 
Northeast
 
South Central
 
West
 
Thermal
 
Total Domestic
 
Inter-national
 
Total Global
Natural gas
 
4,930

 
1,300

 
2,630

 
2,130

 
105

 
11,095

 

 
11,095

Coal
 
4,190

 
1,600

 
1,495

 

 
15

 
7,300

 
1,005

 
8,305

Oil
 

 
4,015

 

 

 

 
4,015

 
 
 
4,015

Nuclear
 
1,175

 

 

 

 

 
1,175

 

 
1,175

Wind
 
450

 

 

 

 

 
450

 

 
450

Utility Scale Solar
 

 

 

 
65

 

 
65

 

 
65

Distributed Solar
 

 

 

 
30

 

 
30

 

 
30

Total generation capacity
 
10,745

 
6,915

 
4,125

 
2,225

 
120

 
24,130

 
1,005

 
25,135

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Under Construction
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas
 

 

 

 
550

 

 
550

 

 
550

Utility Scale Solar (a)
 

 

 

 
855

 

 
855

 

 
855

Distributed Solar
 

 

 

 
5

 

 
5

 

 
5

Total under construction
 

 

 

 
1,410

 

 
1,410

 

 
1,410

(a) Includes 142 MWs, representing 49% of Agua Caliente's capacity, which was sold to a partner on January 18, 2012
        
In addition, the Company's thermal assets provide steam and chilled water capacity of approximately 1,170 megawatts thermal equivalent, or MWt, through its district energy business.

Reliability of future cash flows and portfolio diversification  

NRG has hedged a portion of its expected baseload generation capacity with decreasing hedge levels through 2016. NRG also has cooperative load contract obligations in the South Central region expiring over various dates through 2025, which largely hedge the Company's generation in this region. In addition, as of December 31, 2011, the Company had purchased fuel forward under fixed price contracts, with contractually-specified price escalators, for approximately 42% of its expected baseload coal requirement from 2012 to 2016, excluding inventory. The Company has the capacity and intent to enter into additional hedges when market conditions are favorable.

The Company also has the advantage of being able to supply its Retail Businesses with its own generation, which can reduce the need to sell and buy power from other financial institutions and intermediaries, resulting in lower transaction costs and credit exposures. This combination of generation and retail allows for a reduction in actual and contingent collateral, through offsetting transactions and by reducing the need to hedge the retail power supply through third parties.

The generation and retail combination also provides stability in cash flows, as changes in commodity prices generally have offsetting impacts between the two businesses. The offsetting nature of generation and retail in relation to changes in market prices, is an integral part of NRG's goal of providing a reliable source of future cash flow for the Company.

When developing renewable and new, conventional power generation facilities, NRG typically secures long-term Power Purchase Agreements, or PPAs, which insulate the Company from commodity market volatility and provide future cash flow stability. These PPAs are typically contracted with high credit quality local utilities and have durations up to 25 years. Such projects include all of the Company's major Utility Scale Solar projects, in operation and under construction, as well as the 550 MW El Segundo Energy Center, or ESEC, project that is under construction.


11


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

Baseload Operations

The following table summarizes NRG's U.S. Baseload capacity and the corresponding revenues and average natural gas prices and positions resulting from Baseload hedge agreements extending beyond February 14, 2012, and through 2016:

 
2012 (a)
 
2013
 
2014
 
2015
 
2016
 
Annual
Average for
2012-2016
 
(Dollars in millions unless otherwise stated)
Net Baseload Capacity (MW) (b)
8,466

 
8,466

 
8,311

 
8,311

 
8,311

 
8,373

Forecasted Baseload Capacity (MW) (c)
5,823

 
5,797

 
5,453

 
5,818

 
6,013

 
5,781

Total Baseload Sales (MW) (d)
5,761

 
4,756

 
3,098

 
1,407

 
1,399

 
3,284

Percentage Baseload Capacity Sold Forward (e)
99
%
 
82
%
 
57
%
 
24
%
 
23
%
 
57
%
Total Forward Hedged Revenues (f)(g)
$
2,236

 
$
1,909

 
$
1,103

 
NM (h)

 
NM (h)

 
 
Weighted Average Hedged Price ($ per MWh) (f)
$
52.86

 
$
45.83

 
$
40.64

 
NM (h)

 
NM (h)

 
 
Average Equivalent Natural Gas Price ($ per MMBtu)
$
5.38

 
$
5.29

 
$
4.80

 
NM (h)

 
NM (h)

 
 
Baseload Gas $1/MMBtu Up Sensitivity
$
50

 
$
145

 
$
259

 
$
368

 
$
387

 
 
Baseload Gas $1/MMBtu Down Sensitivity
$

 
$
(46
)
 
$
(180
)
 
$
(329
)
 
$
(350
)
 
 
Baseload Heat Rate 1 MMBtu/MWh Up Sensitivity
$
16

 
$
70

 
$
146

 
$
171

 
$
209

 
 
Baseload Heat Rate 1 MMBtu/MWh Down Sensitivity
$
(1
)
 
$
(47
)
 
$
(119
)
 
$
(157
)
 
$
(191
)
 
 
(a)
2012 represents the period March through December.
(b)
Nameplate capacity net of station services reflecting unit retirement schedule.
(c)
Forecasted generation dispatch output (MWh) based on forward price curve as of February 14, 2012, which is then divided by number of hours in a given year to arrive at MW capacity. The dispatch takes into account planned and unplanned outage assumptions.
(d)
Includes amounts under power sales contracts and natural gas hedges. The forward natural gas quantities are reflected in equivalent MWh based on forward market implied heat rate as of February 14, 2012, and then combined with power sales to arrive at equivalent MWh hedged which is then divided by number of hours in given year to arrive at MW hedged. The Baseload Sales include swaps and delta of options sold which is subject to change. For detailed information on the Company's hedging methodology through use of derivative instruments, see discussion in Item 15 - Note 6, Accounting for Derivative Instruments and Hedging Activities, to the Consolidated Financial Statements. Includes inter-segment sales from the Company's Texas wholesale power generation business to the Retail Businesses.
(e)
Percentage hedged is based on total baseload sales as described in (d) above divided by the forecasted baseload capacity.
(f)
Represents all North American baseload sales, including energy revenue and demand charges.
(g)
The South Central region's weighted average hedged prices ranges from $40/MWh-$50/MWh. These prices include demand charges and an estimated energy charge.
(h)
NM — Not meaningful, as South Central hedges, which are subject to renegotiation of the transportation component of coal costs, represent a substantial portion of total hedges.



12


Retail Operations

NRG's retail operations sell electricity on fixed price or indexed products, and these contracts have terms typically ranging from one month to five years. In 2011, the Company's Retail Businesses sold approximately 57 TWh of load. In any given year, TWh sold can be affected by weather, economic conditions and competition. The wholesale supply is typically purchased as the load is contracted in order to secure profit margin. The wholesale supply is purchased from a combination of NRG's wholesale portfolio and other third parties, depending on the existing hedge position for the NRG wholesale portfolio at the time.

Capacity and Other Contracted Revenue Sources

NRG revenues and cash flows benefit from capacity/demand payments and other contracted revenue sources, originating from either market clearing capacity prices, Resource Adequacy, or RA, contracts, tolling arrangements, PPAs and other long-term contractual arrangements:
Northeast — The Company's largest sources for capacity revenues are derived from market capacity auctions in ISO New England Inc., or ISO-NE, New York Independent System Operator, or NYISO, and PJM Interconnection LLC, or PJM. The region's share of the GenConn plants in Connecticut earns fixed payments for their output under long-term financial contracts with a utility counterparty.
South Central — NRG earns demand payments from its long-term full-requirements load contracts with ten Louisiana distribution cooperatives. Of the ten contracts, seven expire in 2025 and account for 57% of the cooperative customer contract load, with the remaining three contracts currently set to expire in 2014. The Company has executed agreements to extend the contracts of two of these three cooperatives representing 19% of the cooperative load through 2025, subject to regulatory approval.  The remaining counterparty, with a 550 MW load service contract, accounting for 24% of the cooperative total, has elected not to extend their contract when it expires in 2014.  Demand payments from the current long term contracts are tied to summer peak demand and provide a mechanism for recovering a portion of costs associated with new or changed environmental laws or regulations.
West — Many of the region's sites, including solar and gas projects currently under construction, are under either long-term PPAs, tolling agreements, or renewable incentive agreements. The remaining sites have short-term RA contracts.
Thermal — Output from the Company's thermal assets is generally sold under long-term contracts or through regulated public utility tariffs. The contracts or tariffs contain capacity or demand elements, mechanisms for fuel recovery and/or the recovery of operating expenses. Thermal output from the Thermal region's Northwind business is sold under long-term agreements with customers in Phoenix, while the PJM assets participate in the PJM capacity markets.
Texas — The region's sources of capacity and contracted revenues are through a PPA contract for South Trent wind generation, capacity option premium agreements, and black start agreements with ERCOT.
International — Generation output from the Company's share of the Schkopau facility in Germany and the Gladstone facility in Australia is sold under long-term contracts, which include capacity payments as well as the reimbursement of certain fixed and variable costs.

Fuel Supply and Transportation

NRG's fuel requirements consist of nuclear fuel and various forms of fossil fuel including coal, natural gas and oil. The prices of fossil fuels are highly volatile. The Company obtains its fossil fuels from multiple suppliers and transportation sources. Although availability is generally not an issue, localized shortages, transportation availability and supplier financial stability issues can and do occur. The preceding factors related to the sources and availability of raw materials are fairly uniform across the Company's business segments.

Coal — The Company is completely hedged for its domestic coal consumption for 2012; less so for subsequent years. Coal hedging is dynamic and is based on forecasted generation and market volatility. As of December 31, 2011, NRG had purchased forward contracts to provide fuel for approximately 42% of the Company's expected requirements from 2012 through 2016, excluding inventory. NRG arranges for the purchase, transportation and delivery of coal for the Company's baseload coal plants via a variety of coal purchase agreements, rail/barge transportation agreements, and rail car lease arrangements. The Company purchased approximately 27 million tons of coal in 2011, of which 98% was Powder River Basin coal and lignite.


13


The following table shows the percentage of the Company's coal requirements from 2012 through 2016 that have been purchased forward as of December 31, 2011:
 
Percentage of
Company's
Requirement (a)(b)
2012
100
%
2013
52
%
2014
21
%
2015
20
%
2016
17
%
(a)
The hedge percentages reflect the current plan for the Jewett mine, which supplies lignite for NRG's Limestone facility. NRG has the contractual ability to change volumes and may do so in the future.
(b)
Does not include coal inventory.

As of December 31, 2011, NRG had approximately 5,900 privately leased or owned rail cars in the Company's transportation fleet. NRG has entered into rail transportation agreements with varying tenures that provide for substantially all of the Company's rail transportation requirements for the next three years.

Natural Gas — NRG operates a fleet of natural gas plants across all its U.S. wholesale regions, which are primarily comprised of peaking assets that run in times of high power demand. Due to the uncertainty of their dispatch, the fuel needs are managed on a spot basis as the Company does not believe it is prudent to forward purchase natural gas for units, the dispatch of which is highly unpredictable. The Company contracts for natural gas storage services as well as natural gas transportation services to ensure delivery of natural gas when needed.

Nuclear Fuel — South Texas Project's, or STP's, owners satisfy STP's fuel supply requirements by: (i) acquiring uranium concentrates and contracting for conversion of the uranium concentrates into uranium hexafluoride; (ii) contracting for enrichment of uranium hexafluoride; and (iii) contracting for fabrication of nuclear fuel assemblies. Through its proportionate participation in South Texas Project Nuclear Operating Company, or STPNOC, which is the U.S. Nuclear Regulatory Commission, or NRC, -licensed operator of STP and responsible for all aspects of fuel procurement, NRG is party to a number of long-term forward purchase contracts with many of the world's largest suppliers covering STP requirements for uranium and conversion services for the next five years, and with substantial portions of STP's requirements procured thereafter. Similarly, 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 of the Company's wholesale power generation segments can be significantly affected by weather and energy commodity price volatility. Significant other events, such as the demand for natural gas, interruptions in fuel supply infrastructure and relative levels of hydroelectric capacity can increase seasonal fuel and power price volatility. NRG derives a majority of its annual revenues in the months of May through October, when demand for electricity is generally at its highest in the Company's core domestic markets. Further, power price volatility is generally higher in the summer months, traditionally NRG's most important season. The Company's second most important season is the winter months of December through March when volatility and price spikes in underlying delivered fuel prices have tended to drive seasonal electricity prices. The preceding factors related to seasonality and price volatility are fairly uniform across the Company's wholesale generation business segments.

The sale of electric power to retail customers is also a seasonal business with the demand for power generally peaking during the summer months. As a result, net working capital requirements for the Company's retail operations generally increase during summer months along with the higher revenues, and then decline during off-peak months. Weather may impact operating results and extreme weather conditions could materially affect results of operations. The rates charged to retail customers may be impacted by fluctuations in the price of natural gas, transmission constraints, competition, and changes in market heat rates.


14


Regional Segment Review

Revenues

The following table contains a summary of NRG's operating revenues by segment for the years ended December 31, 2011, 2010, and 2009, as discussed in Item 15 — Note 18, Segment Reporting, to the Consolidated Financial Statements. Refer to that footnote for additional financial information about NRG's business segments and geographic areas, including a profit measure and total assets. In addition, refer to Item 2 — Properties, for information about facilities in each of NRG's business segments.
 
Year Ended December 31, 2011
 
Energy
Revenues
 
Capacity
Revenues
 
Retail
Revenues
 
Mark-to-
Market
Activities
 
Contract Amor-tization
 
Thermal Revenues
 
Other
Revenues
 
Total
Operating
Revenues
 
(In millions)
Reliant Energy
$

 
$

 
$
5,075

 
$
8

 
$
(145
)
 
$

 
$

 
$
4,938

Texas
2,561

 
28

 

 
173

 

 

 
106

 
2,868

Northeast
579

 
291

 

 
28

 

 

 
26

 
924

South Central
548

 
243

 

 
(12
)
 
20

 

 
18

 
817

West
42

 
118

 

 
(4
)
 

 

 
4

 
160

International
58

 
70

 

 

 

 

 
16

 
144

Thermal

 

 

 

 
(1
)
 
143

 

 
142

Corporate and Eliminations (a)(b)
(1,719
)
 
(14
)
 
732

 
132

 
(33
)
 

 
(12
)
 
(914
)
Total
$
2,069

 
$
736

 
$
5,807

 
$
325

 
$
(159
)
 
$
143

 
$
158

 
$
9,079

(a)
Energy revenues include inter-segment sales primarily between Texas and Northeast, and the Retail Businesses.
(b)
Retail revenues include Energy Plus retail revenues of $63 million for the period October 1, 2011, to December 31, 2011.

 
Year Ended December 31, 2010
 
Energy
Revenues
 
Capacity
Revenues
 
Retail
Revenues
 
Mark-to-
Market
Activities
 
Contract Amor-tization
 
Thermal Revenues
 
Other
Revenues
 
Total
Operating
Revenues
 
(In millions)
Reliant Energy
$

 
$

 
$
5,210

 
$
(1
)
 
$
(219
)
 
$

 
$

 
$
4,990

Texas
2,850

 
25

 

 
57

 
7

 

 
118

 
3,057

Northeast
726

 
396

 

 
(144
)
 

 

 
47

 
1,025

South Central
387

 
235

 

 
(45
)
 
21

 

 
10

 
608

West
31

 
113

 

 
(4
)
 

 

 
4

 
144

International
46

 
71

 

 

 

 

 
11

 
128

Thermal

 

 

 
(2
)
 

 
145

 

 
143

Corporate and Eliminations (c)(d)
(1,186
)
 
(16
)
 
67

 
(60
)
 
(4
)
 

 
(47
)
 
(1,246
)
Total
$
2,854

 
$
824

 
$
5,277

 
$
(199
)
 
$
(195
)
 
$
145

 
$
143

 
$
8,849

(c)
Energy revenues include inter-segment sales primarily between Texas and both Reliant Energy and Green Mountain Energy.
(d)
Retail revenues include Green Mountain Energy retail revenues of $69 million for the period November 5, 2010, to December 31, 2010.

 
Year Ended December 31, 2009
 
Energy
Revenues
 
Capacity
Revenues
 
Retail
Revenues
 
Mark-to-
Market
Activities
 
Contract Amor-tization
 
Thermal Revenues
 
Other
Revenues
 
Total
Operating
Revenues
 
(In millions)
Reliant Energy (e)
$

 
$

 
$
4,440

 
$

 
$
(258
)
 
$

 
$

 
$
4,182

Texas
2,770

 
193

 

 
(17
)
 
57

 

 
(57
)
 
2,946

Northeast
873

 
407

 

 
(70
)
 

 

 
(9
)
 
1,201

South Central
367

 
269

 

 
(17
)
 
22

 

 
(60
)
 
581

West
26

 
122

 

 

 

 

 
2

 
150

International
52

 
79

 

 

 

 

 
13

 
144

Thermal

 

 

 
(2
)
 

 
137

 

 
135

Corporate and Eliminations (f)
(362
)
 
(47
)
 

 
(1
)
 

 

 
23

 
(387
)
Total
$
3,726

 
$
1,023

 
$
4,440

 
$
(107
)
 
$
(179
)
 
$
137

 
$
(88
)
 
$
8,952

(e)
For the period May 1, 2009, to December 31, 2009.
(f)
Energy revenues include inter-segment sales between Texas and Reliant Energy.

15


Operational Statistics

The following are industry statistics for the Company's fossil and nuclear plants, as defined by the North American Electric Reliability Council, or NERC, and are more fully described below:

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

Net heat rate — The net heat rate represents the total amount of fuel in British Thermal Unit, or BTU, required to generate one net kWh provided.

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 these performance metrics for the Company's U.S. power generation portfolio, including those accounted for through equity method investments, for the years ended December 31, 2011, and 2010:

 
Year Ended December 31, 2011
 
 
 
 
 
Fossil and Nuclear Plants
 
Net Owned
Capacity (MW)
 
Net
Generation
(MWh)
 
Annual
Equivalent
Availability
Factor
 
Average Net
Heat Rate
BTU/kWh
 
Net Capacity
Factor
 
(In thousands of MWh)
Texas 
10,745

 
46,348

 
88.2
%
 
10,300

 
46.7
%
Northeast (a)
6,915

 
7,376

 
87.2

 
11,100

 
11.1

South Central
4,125

 
16,000

 
89.9

 
9,700

 
43.9

West
2,225

 
1,131

 
88.5

 
12,400

 
5.6


 
Year Ended December 31, 2010
 
 
 
 
 
Fossil and Nuclear Plants
 
Net Owned
Capacity (MW)
 
Net
Generation
(MWh)
 
Annual
Equivalent
Availability
Factor
 
Average Net
Heat Rate
BTU/kWh
 
Net Capacity
Factor
 
(In thousands of MWh)
Texas
10,745

 
44,700

 
89.6
%
 
10,300

 
48.1
%
Northeast (a)
6,900

 
9,366

 
88.3

 
11,000

 
14.1

South Central (b)
4,125

 
11,168

 
91.3

 
10,500

 
41.9

West
2,150

 
921

 
89.7

 
11,800

 
4.8

 
(a)
Factor data and heat rate do not include the Keystone and Conemaugh facilities.
(b)
Includes Cottonwood for the period November 15, 2010 (acquisition date), to December 31, 2010.


16


The generation performance by region for the three years ended December 31, 2011, 2010, and 2009, is shown below:

 
Net Generation
 
2011
 
2010
 
2009
 
(In thousands of MWh)
Texas
 
 
 
 
 
Coal
30,256

 
29,633

 
30,023

Gas (a)
5,949

 
4,794

 
5,224

Nuclear (b)
8,960

 
9,295

 
9,396

Wind
1,183

 
978

 
350

Total Texas
46,348

 
44,700

 
44,993

Northeast
 
 
 
 
 
Coal
5,551

 
7,905

 
7,945

Oil
83

 
114

 
134

Gas
1,742

 
1,347

 
1,141

Total Northeast
7,376

 
9,366

 
9,220

South Central
 
 
 
 
 
Coal
10,865

 
10,778

 
10,235

Gas (c)
5,135

 
390

 
163

Total South Central
16,000

 
11,168

 
10,398

West
 
 
 
 
 
Gas
1,052

 
869

 
639

Solar
79

 
52

 
1

Total West
1,131

 
921

 
640

(a)
MWh information reflects the undivided interest in total MWh generated by Cedar Bayou 4 beginning June 2009.
(b)
MWh information reflects the Company's undivided interest in total MWh generated by STP.
(c)
Includes Cottonwood since November 15, 2010 (acquisition date).

17


Market Framework

Texas

NRG's largest wholesale power generation business segment is located in Texas in the physical control areas of the ERCOT market. In addition, Reliant Energy, Green Mountain Energy and Energy Plus activities in Texas are subject to standards and regulations adopted by the PUCT and ERCOT. In the ERCOT market, NRG's Retail Businesses are certified by the PUCT as Retail Electric Providers, or REPs, to contract with end-users to sell electricity and provide other value-enhancing services. In addition, NRG's Retail Businesses contract with transmission and distribution service providers, or TDSPs, to arrange for transportation to the customer.

The ERCOT market is one of the nation's largest and historically fastest growing power markets. For 2011, hourly demand ranged from a low of approximately 22,000 MW to a high of over 68,000 MW with installed generation capacity of approximately 81,000 MW (24,000 MW from coal, lignite and nuclear plants, 48,000 MW from gas, and 9,000 MW from wind). The ERCOT market has limited interconnections compared to other markets in the United States.

In November 2010, the ERCOT board of directors approved a new target equilibrium reserve margin level of 13.75%. The summer reserve margin for 2011 was forecast to be 18.4% in ERCOT's May 2011 Capacity, Demand and Reserve Report, or CDR. The latest CDR, initially published in December 2011, but updated in January 2012, forecasts a reserve margin level of 13.86% for Summer 2012. There are currently plans being implemented by the PUCT to build a significant amount of transmission from west Texas, the Texas panhandle, and continuing across the state to enable wind generation to reach load. The ultimate impact on wholesale dynamics from these plans are unknown. Currently, due to its intermittency and Texas' typically lower wind speeds during the summer months, ERCOT utilizes a capacity factor of 8.7% for the installed wind units when calculating the summer reserve margins.
 
On December 1, 2010, in compliance with a rule adopted by the PUCT, ERCOT replaced the zonal wholesale market design with a nodal market design that is based on Location Marginal Prices, or LMPs. The new nodal market, operational for all of 2011, includes, among other design changes, a financially binding day-ahead energy and ancillary services market administered by ERCOT. The nodal market design has resulted in improved dispatch of generation resources, more efficient management of transmission congestion, and an improved ability to integrate increased quantities of intermittent resources, such as wind and solar generating resources. Transmission congestion costs in the nodal market are directly assigned to the parties causing the congestion.

In response to projected shortfalls in planning reserves, and real time supply constraints in August 2011, at the direction of the PUCT, the ERCOT Independent System Operator, or ISO, is developing and implementing a number of market rule changes designed to achieve real-time energy pricing more reflective of higher energy value when ISO operating reserves are scarce or constrained - and thus improve forward market pricing signals and provide incentives for resource investment.  Energy offer floors for certain ancillary service deployments have been implemented; other proposals under review include administrative pricing adjustments during operational shortages, higher energy pricing for ISO unit commitments for capacity, mitigation of price dampening from minimum energy from on-line resources, and formalizing emergency supply procurement by the ISO in a manner that would not suppress competitive pricing.


18


Northeast

NRG's second largest asset base is located in the Northeast region of the United States with generation assets within the control areas of the NYISO, ISO-NE, and PJM. Although each of the three NYISOs, also referred to as Regional Transmission Organizations, or RTOs, and their respective energy markets are functionally, administratively and operationally independent, they all follow, to a certain extent, similar market designs. Each ISO optimizes the scheduling and dispatch of power plant capabilities and price offers to meet system energy and reliability needs, and settles financial and physical energy deliveries at LMPs. LMPs reflect the value of energy at the specific location and time it is delivered. The LMP is determined by dispatching generators with the least cost energy supply offers to create the most reliable and economic solution where the energy is needed, subject to reliability and operational constraints on the system or individual generators. The ISO-sponsored LMP energy markets consist of two separate and characteristically distinct settlement time-frames. The first time-frame is a financially firm, day-ahead unit commitment market. The second time-frame is a financially settled, real-time dispatch and balancing market that fluctuates over a 24 hour period. All of these LMP energy markets are subject to stringent 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. In addition to the energy markets, each of the Northeast ISOs operates a capacity market that provides an additional opportunity for generating and demand response resources to earn revenues to offset their fixed costs that are not recovered in the energy markets, and reserve markets.

NRG's Retail Businesses are active in a number of areas in the Northeast region that have introduced retail competition, which allows our businesses to competitively provide retail power, natural gas and other value-enhancing services to customers. Each retail choice state is responsible for its own retail competition laws and regulations, and the specific operational, licensing, and compliance requirements vary on a state-by-state basis.  In general, our Retail Businesses purchase energy from the wholesale market and utilize the existing transmission and distribution system to provide that power to end-use customers. Primary factors in the success of retail competition include how the state provides and prices default service.  Incumbent utilities currently provide default service and as a result typically serve a majority of residential customers.  However, as customers become more informed about the many benefits of retail choice and states continue to implement retail policies to further improve market dynamics, retail choice is expected to grow. The Company's Retail Businesses are currently licensed in many of the states allowing for retail choice in either the Commercial, industrial and governmental/institutional, or C&I, or Residential markets. Our Retail Businesses are expanding into a number of competitive choice states and offering a plethora of value propositions to customers to meet individual consumer preferences. 

South Central

NRG's South Central region operates primarily in the Southeastern Electric Reliability Council/Entergy, or SERC-Entergy, region, which is a bilateral market without an RTO. In the South Central region, all power sales and purchases are consummated bilaterally between individual counterparties. Transacting counterparties are required to procure transmission service from the relevant transmission owners at their Federal Energy Regulatory Commission, or FERC, -approved tariff rates. In this market structure, NRG is able to provide balancing authority services in addition to wholesale power that allows NRG to provide full requirement services to load-serving entities, thus making NRG a competitive alternative to the integrated utilities operating in the region. NRG operates four Balancing Authorities, including the LAGEN Balancing Authority, which encompasses the generating facilities, the Company's cooperative load, and certain municipal entities purchasing long-term firm power from NRG.

West & Solar

The Company operates a fast-growing fleet of Utility Scale Solar and Distributed Solar generating assets within the balancing authority of the California Independent System Operator, or CAISO, as well as neighboring systems, and operates a fleet of natural gas fired facilities located entirely within the CAISO footprint. The CAISO operates day-ahead and real-time locational markets for energy and ancillary services, while managing congestion through nodal price fluctuations. The CAISO system facilitates NRG's sale of power and capacity products at market-based rates, or bilaterally pursuant to tolling arrangements with California's load serving entities, or LSEs. The CAISO, in conjunction with the California Public Utilities Commission, or CPUC, also determines specific capacity requirements for specified local areas. Both CAISO and CPUC rules require LSEs to contract with sufficient generation resources in order to maintain minimum levels of generation within defined local reliability areas.


19


California's resource mix is being significantly shaped by California's renewable portfolio standard and its greenhouse gas reduction rules. In particular, the state's renewable portfolio standard is 33% by 2020. In part driven by the renewable portfolio standard, several LSEs have entered into long-term PPAs with the Company's California and Arizona-based Utility Scale Solar generating facilities. The Company currently has PPAs for over 890 MW of solar generation assets both within the CAISO balancing authority, and selected markets outside of California, including Arizona. These contracts were approved by the CPUC.

The renewable portfolio standard is also expected to drive the need for generation resources with increased operating flexibility. The need is expected to be particularly acute in constrained areas of the transmission system, such as the San Diego and Los Angeles local reliability areas in which the Company currently operates natural gas-fired generation. The projected retirement of older flexible gas-fired coastal generating units that utilize once-through cooling is also a significant driver of long-term prices in California. Implementing market mechanisms to procure the needed flexibility, and allocating the costs associated with this flexibility, are key CAISO 2012 initiatives. NRG's CAISO natural gas-fired assets are in the Los Angeles or San Diego local reliability areas, and may benefit from local capacity requirements. The Company's El Segundo Energy Center development, which is currently under construction and the subject of a long-term tolling agreement, is an example of the type of flexible natural gas-fired generation resource that the CAISO has suggested will be necessary to maintain system reliability. Longer term, NRG's California portfolio's locational advantage may be impacted by new transmission, which may affect load pocket procurement requirements, and by the state's goal for additional distributed generation, which may also be located within these constrained local areas.


20


New and On-going Company Initiatives and Development Projects

NRG has a comprehensive set of initiatives and development projects that supports its strategy focused on: (i) excellence in safety and enhanced operating performance; (ii) earning a margin by selling electricity to end-use customers; (iii) development of new renewable and conventional power generation projects and repowering of power generation assets at existing sites; (iv) empowering retail customers with distinctive products and services; (v) engaging in a proactive capital allocation plan; and (vi) pursuing selective acquisitions, joint ventures, divestitures and investment in new energy-related businesses and new technologies in order to enhance the Company's asset mix and combat climate change.

Renewable Development and Acquisitions

As part of its core strategy, NRG has started and intends to continue to invest significantly in the development and acquisition of renewable energy projects, primarily solar. NRG's renewable strategy is intended to capitalize on first mover advantage in a high growth segment of NRG's business, the Company's existing presence in regions with attractive renewable resources and the prevalence, in the Company's core markets, of state-mandated renewable portfolio standards. A brief description of the Company's development efforts with respect to each renewable technology follows.

Solar

NRG has acquired and is developing a number of solar projects utilizing photovoltaic, or PV, as well as solar thermal technologies. The following table is a brief summary of the Company's major Utility Scale Solar projects as of December 31, 2011, that are under construction.
NRG Owned Projects
Location
PPA
MW (a)
Expected COD
Status
Ivanpah
Ivanpah, CA
20 - 25 year
392

2013
Under Construction
Agua Caliente (b)
Yuma County, AZ
25 year
290

2012 - 2014
Under Construction
CVSR
San Luis Obispo, CA
25 year
250

2012 - 2013
Under Construction
Alpine
Lancaster, CA
20 year
66

2012
Under Construction
Borrego
Borrego Springs, CA
25 year
26

2012
Under Construction
Avra Valley
Pima County, AZ
25 year
25

2012
Under Construction
(a) Represents total project size.
(b) Includes a 30 MW block, which reached commercial operations on January 18, 2012.
 
Below is a summary of recent developments related to solar projects:

Ivanpah On April 5, 2011, NRG acquired a 50.1% stake in the 392 MW Ivanpah Solar Electric Generation System, or Ivanpah, from BrightSource Energy, Inc., or BSE. BSE maintained a 21.8% interest in Ivanpah and the remaining 28.1% was acquired by a wholly-owned subsidiary of Google. Ivanpah is composed of three separate facilities - Ivanpah 1 (126 MW), Ivanpah 2 (133 MW), and Ivanpah 3 (133 MW). Operations for the first phase are scheduled to commence in the first quarter of 2013, with the second and third phases expected to reach commercial operations in the second and third quarters of 2013, respectively. Power generated from Ivanpah will be sold to Southern California Edison and Pacific Gas and Electric, under multiple 20 to 25 year PPAs. Ivanpah has entered into the Ivanpah Credit Agreement with the Federal Financing Bank, or FFB, which is guaranteed by the United States Department of Energy, or U.S. DOE, to borrow up to $1.6 billion to fund the construction of this solar facility. On June 10, 2011, the U.S. Fish and Wildlife Service, or FWS, issued a revised biological opinion allowing the Bureau of Land Management to lift its temporary suspension of activities order with respect to the Ivanpah Project, thus allowing those aspects of the project which were delayed to proceed.

Western Watershed Project filed a motion seeking a temporary restraining order against the Ivanpah Project on June 27, 2011, to shut the project down in order to protect the desert tortoise as well as other animals. It was denied as was plaintiff's request for a preliminary injunction. The plaintiffs appealed this decision on August 20, 2011 to the U.S. Court of Appeals for the Ninth Circuit. On January 27, 2012, the district court heard arguments on the parties' cross motions for summary judgment. The Company awaits the court's rulings.


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Agua Caliente On August 5, 2011, NRG acquired 100% of the 290 MW Agua Caliente solar project, or Agua Caliente, in Yuma, AZ. Operations are scheduled to commence in phases, with the first 30 MW block achieving commercial operations on January 19, 2012, and the final block scheduled to come on line in the first quarter of 2014. Power generated from Agua Caliente will be sold to Pacific Gas and Electric under a 25 year PPA. In connection with the acquisition, Agua Caliente Solar, LLC, a wholly-owned subsidiary of NRG, entered into the Agua Caliente Financing Agreement with the FFB, which is guaranteed by the U.S. DOE, to borrow up to $967 million to fund the construction of this solar facility.

On January 18, 2012, the Company completed the sale of a 49% interest in NRG Solar AC Holdings LLC, the indirect owner of the Agua Caliente project entity, to MidAmerican Energy Holdings Company, or MidAmerican.  A portion of the cash consideration received at closing represented 49% of construction costs funded by NRG's equity contributions. MidAmerican will fund its proportionate share of future equity contributions and other credit support for the project.

CVSR On September 30, 2011, NRG acquired 100% of the 250 MW California Valley Solar Ranch project, or CVSR, in eastern San Luis Obispo County, California. Power generated from CVSR will be sold to Pacific Gas and Electric under a 25 year PPA. In connection with the acquisition, High Plains Ranch II, LLC, a wholly-owned subsidiary of NRG, entered into the CVSR Financing Agreement with the FFB, which is guaranteed by the U.S. DOE, to borrow up to $1.2 billion to fund the construction of this solar facility. The Company continues to work with its partners and the U.S. DOE to satisfy all of the U.S. DOE loan disbursement requirements and funding is anticipated by the end of the first quarter of 2012. Operations are expected to commence in phases beginning in the third quarter of 2012 through the fourth quarter of 2013.

Utility Scale Solar Development Pipeline
 
NRG has a pipeline of solar development projects that currently total approximately 967 MW in generation capacity as of December 31, 2011. The projects in the pipeline, which were either acquired or internally developed, range in size from 20 MW to 238 MW, and have the potential to become operational between 2012 and 2018.
 
Distributed Solar
 
On September 28, 2011, the Company entered into an agreement with Prologis, Inc. to invest in a distributed generation project of up to 733 MW led by Prologis, which includes a U.S. DOE loan guarantee commitment of up to $1.4 billion.

On November 8, 2011, the Company acquired Solar Power Partners, or SPP, a leading developer of commercial and industrial Distributed Solar projects with 21 MW of Distributed Solar projects in operation or under construction.  The acquisition combines the financial resources of NRG with the development and deal structuring capability of SPP to facilitate the build out of SPP's development pipeline of more than 300 MW of projects in early to late stage development in California, Hawaii, Arizona, Connecticut, New Mexico, Massachusetts, New Jersey, Ontario and Puerto Rico.

In furtherance of its Distributed Solar strategy, in December 2011, NRG announced that it will install solar power generating systems at MetLife Stadium, home of the New York Football Giants and New York Jets, as well as Gillette Stadium, home of the New England Patriots. In addition, it will install a solar power generating system at Patriot Place, a shopping, dining, and entertainment venue in Foxborough, Massachusetts. All of the Company's Distributed Solar projects are supported by long-term PPAs.

In support of the Company's solar generation strategy, in the fourth quarter of 2011, NRG Solar purchased solar panels in the aggregate amount of approximately $130 million from various equipment vendors, including SunPower Systems SARL, GCL Solar Energy, Inc., Solar Frontier Americas Inc. and Hanwha SolarOne (Qidong) Co., Ltd.. These transactions will provide economic benefits for designated Utility Scale Solar and Distributed Solar projects in the development pipeline as they are constructed and achieve commercial operation.

 

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Retail Acquisition

On September 30, 2011, NRG acquired Energy Plus, a Philadelphia-based retail electricity and natural gas provider with a customer base principally in New York, Connecticut, Pennsylvania, New Jersey, Maryland, and Illinois. Energy Plus also sells electricity to retail customers in Texas and natural gas in Ohio, New York and New Jersey. As of December 31, 2011, Energy Plus had 188,000 customers from its retail and natural gas businesses combined. Through its rewards program offered through the company's exclusive marketing partnerships with leading loyalty program providers, Energy Plus provides NRG with an additional retail platform to expand its customer services and products in multiple retail markets.

Retail Growth Initiatives

Reliant Energy continues to expand its Reliant eSenseTM product offerings. eSense is a suite of technology solutions that use the advanced meter system network (smart meters) that is being rolled out to customers in ERCOT.  Through December 31, 2011, Reliant has 525,000 customers using one of these products that provide customers insights, choices and convenience solutions. Reliant's eSense development was accelerated by the U.S. DOE grant received during 2010. 

Reliant also continues to expand its Home SolutionsSM business with almost 220,000 customers utilizing home services products including protection products such as surge protection, in home power line protection, HVAC maintenance and energy efficiency products like air filter delivery and solar panel leasing.

Reliant Energy now offers commercial service in Delaware, Illinois, Maryland, New Jersey, Pennsylvania, and Washington, DC.

Electric Vehicle Infrastructure Development

NRG, through its subsidiary eVgo, continues its build out of the Houston and Dallas/Fort Worth Metroplex EV ecosystems, and the Company is on track to be the first company to equip an entire major market with the privately funded infrastructure needed for successful EV adoption and integration. As of December 2011, Houston had the largest single metropolitan-area network of DC fast chargers in the nation. eVgo offers consumers a subscription-based plan that locks in all charging requirements for EVs at a competitive monthly fee. Based upon the successful launch of its subscription-based business model in Texas, eVgo is evaluating a number of other geographical areas for expansion.
In September 2011, NRG, through its subsidiary, eV2g LLC, agreed to partner with the University of Delaware to develop vehicle-to-grid, or V2G, aggregation technology, a new EV infrastructure technology that manages the interaction of plugged-in electric vehicles with the electric grid to provide electricity supply and ancillary services including frequency regulation, demand response and other grid functions.
Post-combustion Carbon Capture Project

On March 9, 2010, NRG was selected by the U.S. DOE to receive up to $167 million, including funding from the American Recovery and Reinvestment Act, to build a 60 MW-equivalent post-combustion carbon capture demonstration unit at NRG's WA Parish plant southwest of Houston, with the intent of using the captured CO2 in enhanced oil recovery operations in oil fields on the Texas Gulf Coast.  In the first half of 2011, an application was submitted to and approved by the U.S. DOE to conduct a front-end engineering and design, or FEED, study for an up-to 250 MW sized project, which would allow for larger volumes of CO2 production, leading to increased oil production through enhanced recovery efforts. The FEED study has been completed, and 50% of the costs of this phase were reimbursed by the U.S. DOE. To further the project's enhanced oil recovery operations, on October 3, 2011, Petra Nova LLC, a wholly-owned subsidiary of NRG, acquired a 50% interest in Texas Coastal Ventures, LLC, which owns a 100% working interest in the West Ranch oil field in Jackson County, Texas. 


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Energy Technology Ventures

On January 27, 2011, NRG entered into a joint venture with GE and ConocoPhillips to invest in venture-stage and growth-stage next generation energy technology companies. The joint venture, Energy Technology Ventures, will invest in and offer commercial collaboration opportunities to emerging energy technology companies in various sectors, including renewable power generation, smart grid, energy efficiency, emission controls, oil, natural gas, coal and biofuels.  As of December 31, 2011, NRG has invested $14 million in several growth companies through Energy Technology Ventures as part of its plan to invest up to $100 million in this joint venture over four years. 

Conventional Power Development

Projects Under Construction

The Company's El Segundo Energy Center LLC, or ESEC, commenced construction at its El Segundo Power Generating Station in El Segundo, California. Full notice to proceed with construction of the 550 MW fast start, gas turbine combined cycle generating facility was provided to the construction vendor on June 6, 2011. On August 23, 2011, the Company through its wholly owned subsidiary, NRG West Holdings LLC, entered into a credit agreement that established a loan facility with respect to ESEC consisting of a $540 million construction loan, $138 million in letter of credit facilities, and a revolving loan facility which permits working capital loans or letters of credit of up to $10 million. At the end of construction, the loan will convert to a term facility with semi annual amortization of principal and interest and a maturity date of August 31, 2023. The Company expects a commercial operation date of August 1, 2013.
 


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Regulatory Matters

As operators of power plants and participants in wholesale and retail energy markets, certain NRG entities are subject to regulation by various federal and state government agencies. These include the Commodities Futures Trading Commission, or CFTC, FERC, NRC, and PUCT, as well as other public utility commissions in certain states where NRG's generating, thermal, or distributed generation assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO markets in which it participates. Likewise, certain NRG entities participating in the retail markets are subject to rules and regulations established by the states in which NRG entities are licensed to sell at retail. NRG must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where the Company operates.

NRG's operations within the ERCOT footprint are not subject to rate regulation by the FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. As discussed below, these operations are subject to regulation by PUCT, as well as to regulation by the NRC with respect to the Company's ownership interest in STP.
 
CFTC
 
The CFTC, among other things, has regulatory oversight authority over the trading of electricity and gas commodities, including financial products and derivatives, under the Commodity Exchange Act, or CEA. On July 21, 2010, President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, which, among other things, aims to improve transparency and accountability in derivative markets. The Dodd-Frank Act increases the CFTC's regulatory authority on matters related to over-the-counter derivatives, market clearing, position reporting, and capital requirements. The Company expects that in 2012 the CFTC will clarify the scope of the Dodd-Frank Act and issue final rules concerning a central clearing and execution exemption for derivative end-users, margin requirements for transactions, the definition of a “swap” and other issues that will affect the Company's over-the-counter derivatives trading. Because there are many details that remain to be addressed in CFTC rulemaking proceedings, at this time we cannot measure the impact to the Company on its current operations or collateral requirements.
 
FERC
 
The FERC, among other things, regulates the transmission and the wholesale sale of electricity in interstate commerce under the authority of the Federal Power Act, or FPA. The transmission of electric energy occurring wholly within ERCOT is not subject to the FERC's jurisdiction under Sections 203 or 205 of the Federal Power Act. Under existing regulations, the FERC determines whether an entity owning a generation facility is an Exempt Wholesale Generator, or EWG, as defined in the Public Utility Holding Company Act of 2005, or PUHCA of 2005. The FERC also determines whether a generation facility meets the ownership and technical criteria of a Qualifying Facility, or QF, under Public Utility Regulatory Policies Act of 1978, or PURPA. Each of NRG's non-ERCOT U.S. generating facilities qualifies as a QF, or the subsidiary owning the facility qualifies as an EWG.
 
        Federal Power Act — The FPA gives the FERC exclusive rate-making jurisdiction over the wholesale sale of electricity and transmission of electricity in interstate commerce. Under the FPA, the FERC, with certain exceptions, regulates the owners of facilities used for the wholesale sale of electricity or transmission in interstate commerce as public utilities, and establishes market rules that are just and reasonable.
 
Public utilities are required to obtain the FERC's acceptance, pursuant to Section 205 of the FPA, of their rate schedules for the wholesale sale of electricity. All of NRG's non-QF generating and power marketing entities located outside of ERCOT make sales of electricity pursuant to market-based rates, as opposed to traditional cost-of-service regulated rates. Every three years FERC conducts a review of the Company's market based rates and potential market power on a regional basis. In 2011, FERC approved NRG's market power update filing for its Northeast assets.
 
The FPA also gives the FERC jurisdiction to review certain transactions and numerous other activities of public utilities. Section 203 of the FPA requires the FERC's prior approval for the transfer of control of assets subject to the FERC's jurisdiction. Section 204 of the FPA gives the FERC jurisdiction over a public utility's issuance of securities or assumption of liabilities. However, the FERC typically grants blanket approval for future securities issuances and the assumption of liabilities to entities with market-based rate authority.
 

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In accordance with the Energy Policy Act of 2005, or EPAct of 2005, the FERC has approved the NERC as the national Energy Reliability Organization, or ERO. As the ERO, NERC is responsible for the development and enforcement of mandatory reliability standards for the wholesale electric power system. In addition to complying with NERC requirements, each NRG entity must comply with the requirements of the regional reliability entity for the region in which it is located.
 
        Public Utility Holding Company Act of 2005 — PUHCA of 2005 provides the FERC with certain authority over and access to books and records of public utility holding companies not otherwise exempt by virtue of their ownership of EWGs, QFs, and Foreign Utility Companies, or FUCOs. NRG is a public utility holding company, but because all of the Company's generating facilities have QF status or are owned through EWGs, it is exempt from the accounting, record retention, and reporting requirements of the PUHCA of 2005.
 
        Public Utility Regulatory Policies Act — PURPA was passed in 1978 in large part to promote increased energy efficiency and development of independent power producers. PURPA created QFs to further both goals, and the FERC is primarily charged with administering PURPA as it applies to QFs. Certain QFs are exempt from regulation, either in whole or in part, under the FPA as public utilities.
 
NRC
 
The NRC is authorized under the Atomic Energy Act of 1954, as amended, or the AEA, among other things, to grant licenses for, and regulate the operation of, commercial nuclear power reactors. As a holder of an ownership interest in STP, NRG is an NRC licensee and is subject to NRC regulation. The NRC license gives the Company the right to only possess an interest in STP but not to operate it. Operating authority under the NRC operating license for STP is held by STPNOC. NRC regulation involves licensing, inspection, enforcement, testing, evaluation, and modification of all aspects of plant design and operation including the right to order a plant shutdown, technical and financial qualifications, and decommissioning funding assurance in light of NRC safety and environmental requirements. In addition, NRC's written approval is required prior to a licensee transferring an interest in its license, either directly or indirectly. As a possession-only licensee, i.e., non-operating co-owner, the NRC's regulation of NRG is primarily focused on the Company's ability to meet its financial and decommissioning funding assurance obligations. In connection with the NRC license, the Company and its subsidiaries have a support agreement to provide up to $120 million to support operations at STP.
 
Decommissioning Trusts — Upon expiration of the operation licenses for the two generating units at STP, currently scheduled for 2027 and 2028, the co-owners of STP are required under federal law to decontaminate and decommission the STP facility. Under NRC regulations, a power reactor licensee generally must pre-fund the full amount of its estimated NRC decommissioning obligations unless it is a rate-regulated utility, or a state or municipal entity that sets its own rates, or has the benefit of a state-mandated non-bypassable charge available to periodically fund the decommissioning trust such that the trust, plus allowable earnings, will equal the estimated decommissioning obligations by the time the decommissioning is expected to begin.
 
NRG, through its 44% ownership interest, is the beneficiary of decommissioning trusts that have been established to provide funding for decontamination and decommissioning of STP. CenterPoint Energy Houston Electric, LLC, or CenterPoint, and American Electric Power, or AEP, collect, through rates or other authorized charges to their electric utility customers, amounts designated for funding NRG's portion of the decommissioning of the facility. See also Item 15 — Note 7, Nuclear Decommissioning Trust Fund, to the Consolidated Financial Statements for additional discussion.
 
In the event that the funds from the trusts are ultimately determined to be inadequate to decommission the STP facilities, the original owners of the Company's STP interests, CenterPoint and AEP, each will be required to collect, through their PUCT-authorized non-bypassable rates or other charges to customers, additional amounts required to fund NRG's obligations relating to the decommissioning of the facility. Following the completion of the decommissioning, if surplus funds remain in the decommissioning trusts, those excesses will be refunded to the respective rate payers of CenterPoint or AEP, or their successors.
 

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PUCT
The Company's Texas generation subsidiaries are registered as power generation companies with the PUCT. The PUCT also has jurisdiction over power generation companies with regard to their sales in the wholesale markets, the implementation of measures to address undue market power or price volatility, and the administration of nuclear decommissioning trusts. The PUCT exercises its jurisdiction both directly, and indirectly, through its oversight of the ERCOT, the regional transmission organization. Certain of the Company's subsidiaries within the Texas region are also subject to regulatory oversight as a power marketer or as a Qualified Scheduling Entity. NRG Power Marketing, LLC, or PML, is registered as a power marketer with the PUCT and thus is also subject to the jurisdiction of the PUCT with respect to its sales in the ERCOT. Certain of the Company's retail entities are competitive REPs, and as such are subject to the rules and regulations of the PUCT governing REPs.
 
New York State Public Service Commission, or NYSPSC

The Company's NYSPSC generation subsidiaries are electric corporations subject to "lightened" regulation by the NYSPSC. As such, the NYSPSC exercises its jurisdictional authority over certain non-rate aspects of the facilities, including safety, retirements, and the issuance of debt secured by recourse to the Company's generation assets located in New York. The Company currently has blanket authorization from the NYSPSC for the issuance of $15 billion of debt.
 
Regional Regulatory Developments
In New England, New York, the Mid-Atlantic region, the Midwest and California, the FERC has approved regional transmission organizations, also commonly referred to as ISOs. Most of these ISOs administer a wholesale centralized bid-based spot market in their regions pursuant to tariffs approved by the FERC and associated ISO market rules. These tariffs/market rules dictate how the capacity and energy markets operate, how market participants may make bilateral sales with one another, and how entities with market-based rates are compensated within those markets. The ISOs in these regions also control access to and the operation of the transmission grid within their regions. In Texas, pursuant to a 1999 restructuring statute, the PUCT granted similar responsibilities to the ERCOT. NRG is affected by rule/tariff changes that occur in the ISO regions.

For further discussion on regulatory developments see Item 15 — Note 23, Regulatory Matters, to the Consolidated Financial Statements.

Texas Region

Nuclear Regulatory Commission, or NRC, Task Force Report — On July 12, 2011, the NRC Near-Term Task Force, or the Task Force, issued its report, which reviewed nuclear processes and regulations in light of the accident at the Fukushima Daiichi Nuclear Power Station in Japan. The Task Force concluded that U.S. nuclear plants are operating safely and did not identify changes to the existing nuclear licensing process nor recommend fundamental changes to spent nuclear fuel storage. The Task Force report made recommendations in three key areas: the NRC's regulatory framework, specific plant design requirements, and emergency preparedness and actions. STPNOC expects the report to be the first step in a longer-term review that the NRC will conduct, along with seeking broad stakeholder input. STPNOC continues to apply lessons learned and work with regulators and industry organizations on appropriate assessments and actions. 

On January 13, 2012, the NRC issued six draft “information request letters,” seeking industry comment on additional recommendations made by the Near-Term Task Force. Topics for comment include how to improve the robustness of existing emergency preparedness plans, whether to mandate on-site availability of emergency response materials, and guidance on how to identify sites vulnerable to flooding, seismic events, or other natural external hazards (such as hurricanes and tornadoes). The NRC has requested feedback from nuclear utilities on its proposed measures. Until further actions are taken by the NRC, the Company cannot predict the impact of the recommendations in the NRC Task Force report, and could be required to make additional investments at STP Units 1 & 2.

Northeast Region

New England — On April 13, 2011, FERC issued an order addressing proposed amendments submitted by ISO-NE to its Forward Capacity Market, or FCM, design, as well as two pending complaints. Among other market revisions, FERC's order extends the price floor for “at least” the fifth (2014/2015) and sixth (2015/2016) Forward Capacity Auctions in order to address the effect of historical out-of-market capacity. On January 19, 2012, FERC issued an order largely denying rehearing of its prior decision. The January 19 order also approved ISO-NE's request to eliminate the price floor as of the seventh (2016/2017) Forward Capacity Auction.

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New York On November 30, 2010, the NYISO filed at FERC its proposed installed capacity demand curves for 2011/2012, 2012/2013, and 2013/2014. The demand curves are a critical determinant of capacity market prices. The Company and other market participants protested the NYISO's filing, and on January 28, 2011, FERC found in favor of generators on a number of issues principally related to determining the cost of new entry and the resulting adjustments to the demand curves should positively affect capacity clearing prices. On May 19, 2011, FERC granted rehearing to remove property taxes from the cost of new entry of new in-city generation, denied other requests for rehearing, and directed the NYISO to make a series of compliance filings to implement the new rate. On September 15, 2011, FERC issued an order accepting the NYISO's compliance filing, and directing the NYISO to implement the new rate, to take effect November 1, 2011. On December 15, 2011, FERC issued an order denying rehearing of its May 19, 2011, order. The Company and other independent generators with interests in the New York City capacity market have requested judicial review of FERC's December 15, 2011, order.
 
In addition, on June 3, 2011, as amended on June 15, 2011, several New York in-city generators filed a complaint with FERC seeking additional transparency into: whether (i) the NYISO was correctly evaluating if new entrants into the capacity markets should be subject to mitigation and, if so, (ii) the NYISO was appropriately setting the level of any mitigation. On June 29, 2011, the NYISO released its July spot capacity auction clearing prices for New York City, which significantly decreased over June clearing prices. Clearing prices for the third quarter 2011 were comparable to the July clearing prices. The apparent cause of this decrease was a decision by the NYISO to allow a new entrant to bid into the July spot capacity auction, either without mitigation or without proper mitigation. Additionally, another new entrant has since indicated that it also received a mitigation exemption from NYISO and that it intends to begin participating in the NYISO capacity market starting with the May 2012 capability period. The addition of this second new entrant may further affect capacity clearing prices in New York. On July 10, 2011, in response to the July spot auction capacity clearing prices, two independent generators filed a second complaint alleging that the NYISO had improperly exempted both new entrants from mitigation, and requested that FERC immediately direct the NYISO to apply its offer-floor market mitigation rules to both new entrants, to resettle the July capacity spot auction, and other relief. The Company filed at FERC in support of applying offer-floor mitigation to the new entrants. On August 31, 2011, FERC issued an interim order on the second complaint directing the NYISO to provide additional information, on a confidential basis, regarding its mitigation decisions, which were filed on September 23, 2011. Several market participants, including the Company, filed comments in response. Both complaints are pending before FERC.

PJM — On April 12, 2011, FERC issued an order addressing a complaint filed by PJM Power Providers Group seeking to require PJM to address the potential adverse impacts of out-of-market generation on the PJM capacity market, as well as PJM's subsequent submission seeking revisions to the capacity market design, in particular the Minimum Offer Price Rule, or MOPR. In its order, FERC generally strengthened the MOPR and the protections against market price distortion from out-of-market generation. On November 17, 2011, FERC largely denied rehearing of its April 12, 2011, order. Several parties have appealed FERC's decision to federal court, and those appeals have been consolidated in the Third Circuit Court of Appeals. The outcome of this proceeding could affect the Company's ability to meet its obligations under New Jersey's Long-Term Capacity Agreement Pilot Program.

South Central Region

On April 25, 2011, Entergy Corporation, or Entergy, announced that it will pursue joining the Midwest Independent System Operator regional transmission organization, or MISO, with a current target date for joining of December 2013. Entergy's proposal is subject to approval from the regulatory commissions of the states of Arkansas, Louisiana, Mississippi, and Texas, as well as the City of New Orleans. The Company's South Central region is dependent upon Entergy's transmission system to conduct its business, and thus would necessarily move with Entergy into MISO. This development is not expected to materially impact the Company's ability to serve its customers in the region, and the Company is continuing to analyze the impact of the possible changes in transmission access and market design.

West Region

California — On March 17, 2011, FERC issued an order on CAISO's proposal to replace its interim backstop Capacity Procurement Mechanism, or CPM, with a permanent version. On December 23, 2011, the parties to the proceeding submitted a proposed settlement that increases the price, quantity and term of contracts given to generating units not otherwise contracted to fulfill California's Resource Adequacy requirements, but nevertheless needed for reliability. The settlement is subject to FERC approval and may increase payments to any non-contracted units called upon to provide reliability service.
  


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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 and NRG expects this trend to continue. The electric generation industry will face new requirements to address air emissions, climate change, combustion byproducts and water use. In general, future laws and regulations are expected to require the addition of emission controls or other environmental quality equipment or the imposition of certain restrictions on the operations of the Company's facilities. NRG expects that future liability under, or compliance with, environmental requirements could have a material effect on the Company's operations or competitive position.
 
Climate Change — NRG emits GHGs in the process of generating electricity. The following table shows the reduction in CO2, which makes up greater than 99% of the Company's GHG emissions, from 2000 to the present. NRG anticipates reductions in its future emissions profile as the Company implements its strategy to add more renewable sources like wind and solar, modernize the fleet through Repowering, improve generation efficiencies, explore methods to capture CO2, and seeks ways to offset GHGs.




The impact from legislation or federal, regional or state regulation of GHGs on the Company's financial performance will depend on a number of factors, including the level of GHG standards under any such regulations, the applicability of offsets, and the extent to which NRG would be entitled to receive CO2 emissions credits without having to purchase them in an auction or on the open market. Thereafter, under any such legislation or regulation, the impact on NRG would depend on the Company's level of success in developing and deploying low and no carbon technologies.
 
Federal Environmental Initiatives
 
        Environmental Regulatory Landscape — In 2011, a number of U.S. Environmental Protection Agency, or U.S. EPA, air regulations were finalized providing more clarity on the impact to electric generating units. A number of regulations with the potential for impact are still in development or under review by the U.S. EPA: New Source Performance Standards, or NSPS, for GHGs, National Ambient Air Quality Standards, or NAAQS, revisions, coal combustion byproducts, and once-through cooling. While most of these regulations have been considered for some time, the outcomes and any resulting impact on NRG cannot be fully predicted until the rules are finalized. The timing and stringency of these regulations will contribute to a framework for the retrofit of existing fossil plants and deployment of new, cleaner technologies in the next decade. See discussion below for more detail.


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Air — The U.S. EPA released the Cross-State Air Pollution Rule, or CSAPR, on July 7, 2011, with additional proposed updates on October 6, 2011. CSAPR was scheduled to replace the Clean Air Interstate Rule, or CAIR, on January 1, 2012. It was designed to bring states into attainment with PM 2.5 and ozone NAAQS, reducing SO2 and NOx emissions from power plants. The proposed implementation employed cap and trade allowance programs starting in 2012 for Group 1 SO2, Group 2 SO2, Annual NOx, and Ozone Season NOx. In 2014, the SO2 cap would be further reduced in Group 1 states. Under CSAPR, use of Acid Rain SO2 and NOx allowances for CAIR would be discontinued and replaced with these completely distinct allowance programs. Acid Rain allowances would still be required on a 1:1 basis under the Acid Rain Program. NRG owns or has minority interests in plants in six states that would be covered by the rule. No plant impairments nor material capital investment were expected for NRG facilities to comply with CSAPR.

State
Group 1 SO2
Group 2 SO2
Annual NOx
Ozone NOx
IL
X
 
X
X
LA
 
 
 
X
MD
X
 
X
X
NY
X
 
X
X
PA
X
 
X
X
TX
 
X
X
X


In the third quarter 2011, the Company recorded an impairment charge of $160 million on the Company's Acid Rain Program SO2 emission allowances, which were recorded as an intangible asset on the Company's balance sheet. The impairment charge reflects the write-off under CSAPR of the value of emission allowances in excess of those required for compliance with the Acid Rain Program.

CSAPR was challenged by numerous petitioners. On December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit stayed the rule pending resolution of the numerous petitions for judicial review. CAIR will remain in effect during the stay. The court has implemented briefing schedules that would allow the CSAPR appeal to be heard as early as April 2012. The Company is unable to predict the final outcome of the court proceeding. There is no material impact to NRG related to the stay.

On March 16, 2011, the U.S. EPA released the proposed Mercury and Air Toxics Standards, or MATS, to control emissions of hazardous air pollutants from coal and oil fired electric generating units. The rule was signed in final form on December 16, 2011, but has not yet been published in the Federal Register (the timing of which will set compliance dates). Requirements include meeting the standards for mercury, acid gases, and certain metals (such as particulate matter) in 2015 on a plantwide basis with the potential for a one year extension. NRG does not anticipate any plant impairments or capital expenditures beyond the current environmental capital expenditures schedule.

On September 22, 2011, the U.S. EPA released draft guidance on the development and submission of state implementation plans, or SIPs, for the 1-hour SO2 standard that was finalized in 2010. States will have to identify areas of non-attainment and submit SIPs by June 2013 and demonstrate attainment by August 2017. If any areas in which NRG owns coal-fired power plants were ultimately designated as non-attainment, it could require further SO2 controls. The Company cannot determine the impact, if any, of the NAAQS until the rules are final.

On December 20, 2011, the U.S. EPA published their intended designations for the 2008 ozone standard. Designations for counties/parishes in which NRG has power plants remained largely unchanged. The U.S. EPA intends to release final designations in the spring of 2012 and a final rule by July 2014. NRG cannot determine the impact, if any, of these NAAQS until the rules are final.

       

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 Waste — On May 4, 2010, the U.S. EPA proposed two options for the regulation of coal combustion residue, commonly known as coal ash. Under the Proposal's first regulatory option, the U.S. EPA would reverse its August 1993 and May 2000 Bevill Regulatory Determinations and list coal ash as a special waste subject to regulation under hazardous waste regulations. The second regulatory option would leave the Bevill Determination in place and regulate disposal of coal ash as non-hazardous. Under both options, an exemption for the beneficial use of coal ash would remain in place. Additionally, under both options, the U.S. EPA would establish dam safety requirements to address the structural integrity of surface impoundments. While it is not possible to predict the impact of this rule until it is final, as proposed it is not expected to have a material impact on NRG's operations, as all NRG flyash disposal sites are dry landfills. However, should the U.S. EPA implement the hazardous waste option, NRG may incur significant costs due to loss of markets for beneficial reuse. Given the recent release of this proposed rule, NRG will continue to monitor developments and their respective impact on the Company's operations

Water — In July 2004, the U.S. EPA published rules governing cooling water intake structures at existing power facilities commonly referred to as the 316(b) Rule. As a result of a decision by the U.S. Court of Appeals for the Second Circuit, the U.S. EPA suspended the rule in July 2007 while preparing a revised version. On March 28, 2011, the U.S. EPA released the proposed 316(b) Rule. States such as California and New York moved ahead with their own more stringent requirements for once-through cooled units, which are expected to satisfy the requirements of the proposed 316(b) Rule. NRG expects to comply with these requirements with a mix of intake and operational modifications.

Regional U.S. Environmental Initiatives

Northeast
On July 20, 2011, the New York State Department of Environmental Conservation, or NYDEC, announced the State's final policy on cooling water intake structures, confirming the Company's planned capital expenditure for cooling water intakes in that state. NRG expects to comply with these requirements with a mix of intake and operational modifications.

West
The California Air Resources Board adopted the state's GHG cap-and-trade program under Assembly Bill 32, or AB32, on October 20, 2011. Participation by the electric generation sector will begin in 2013. NRG does not expect implementation of the GHG cap-and-trade program in California to have a significant adverse financial impact on the Company for a variety of reasons, including the fact that the portion of NRG's California portfolio that is merchant consists mainly of natural gas-fired facilities and the market price of power when dispatched is expected to have embedded in it the market price of allowances. The contracted portion of NRG's portfolio included pass-through language with respect to the obligation to purchase allowances. New NRG renewable projects in California markets will support AB32 requirements for the increased use of renewable energy.
 
The California statewide 316(b) policy to mitigate once-through cooling was effective as of October 1, 2010. NRG's affected plants submitted alternative plans to meet equivalent mitigation criteria which are reflected in our current schedule of environmental capital expenditures. Specified compliance dates for NRG's El Segundo and Encina power plants are December 31, 2015, and December 31, 2017, respectively.

South Central Region
On February 11, 2009, the U.S. Department of Justice, or U.S. DOJ, acting at the request of the U.S. EPA commenced a lawsuit against Louisiana Generating, LLC in the United States District Court in the Middle District of Louisiana alleging violations of the Clean Air Act, or CAA, at the Big Cajun II power plant. This is the same matter for which Notice of Violations, or NOVs, were issued to Louisiana Generating, LLC on February 15, 2005, and on December 8, 2006. Further discussion on this matter can be found in Item 3 — Legal Proceedings, United States of America v. Louisiana Generating, LLC.

Environmental Capital Expenditures
Based on current rules, technology and plans, NRG has estimated that environmental capital expenditures from 2012 through 2016 to meet NRG's environmental commitments will be approximately $553 million. These costs are primarily associated with mercury controls to satisfy MATS on the Company's Big Cajun II, W.A. Parish and Limestone facilities and a number of intake modification projects across the fleet under state or proposed federal 316(b) rules. NRG continues to explore cost effective compliance alternatives to reduce costs. A more detailed discussion of environmental capital expenditures can be found in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources, Capital Expenditures and Environmental Capital Expenditures.

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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 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. Further discussions of affected NRG sites can be found in Item 15 — Note 24, Environmental Matters, to the Consolidated Financial Statements.

Nuclear Waste — The federal government's program to construct a nuclear waste repository at Yucca Mountain, Nevada was discontinued in 2010. In order to meet the federal government's obligations to safely manage used nuclear fuel and radioactive waste under the U.S. Nuclear Waste Policy Act of 1982, the U.S. DOE established a blue ribbon commission to explore alternatives. Also consistent with the Act, owners of nuclear plants, including the owners of STP, entered into contracts setting out the obligations of the owners and the U.S. DOE, including the fees to be paid by the owners for the U.S. DOE's services. Since 1998, the U.S. DOE has been in default on its obligations to begin removing spent nuclear fuel and high-level radioactive waste from reactors, necessitating each site to take steps to construct interim spent fuel storage installations. STP has sufficient capacity in its spent fuel pool through 2016 at which time its dry cask storage facility will be ready for operation.

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. STP's warehouse capacity is adequate for on-site storage until a site in Andrews County, Texas becomes fully operational.

Employees

As of December 31, 2011, NRG had 5,193 employees, approximately 28% of whom were covered by U.S. bargaining agreements. During 2011, the Company did not experience any labor stoppages or labor disputes at any of its facilities.

Available Information

NRG's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, or Exchange Act, are available free of charge through the Company's website, www.nrgenergy.com, as soon as reasonably practicable after they are electronically filed with, or furnished to the United States Securities and Exchange Commission, or SEC. The Company also routinely posts press releases, presentations, webcasts, and other information regarding the Company on the Company's website.


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Item 1A — Risk Factors Related to NRG Energy, Inc.

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

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

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

A significant percentage of the Company's domestic revenues are derived from baseload power plants that are fueled by coal. In many of the competitive markets where NRG operates, the price of power typically is set by natural gas-fired power plants that generally have higher variable costs than NRG's coal-fired baseload power plants. This allows the Company's baseload coal generation assets to earn attractive operating margins compared to plants fueled by natural gas. A decrease in natural gas prices could result in a corresponding decrease in the market price of power that could significantly reduce the operating margins of the Company's baseload generation assets and materially and adversely impact its financial performance. At low enough natural gas prices, gas plants become more economical than coal generation.  In such a price environment, the Company's coal units cycle more often or even shut down until prices or load increases enough to justify running them again.

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

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

changes in generation capacity in the Company's markets, including the addition of new supplies of power from existing competitors or new market entrants as a result of the development of new generation plants, expansion of existing plants or additional transmission capacity;
electric supply disruptions, including plant outages and transmission disruptions;
changes in power transmission infrastructure;
fuel transportation capacity constraints;
weather conditions;
changes in the demand for power or in patterns of power usage, including the potential development of demand-side management tools and practices;
development of new fuels and new technologies for the production of power;
development of new technologies for the production of natural gas
regulations and actions of the ISOs; and
federal and state power market and environmental regulation and legislation.

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.


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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:

weather conditions;
seasonality;
demand for energy commodities and general economic conditions;
disruption or other constraints or inefficiencies of electricity, gas or coal transmission or transportation;
additional generating capacity;
availability and levels of storage and inventory for fuel stocks;
natural gas, crude oil, refined products and coal production levels;
changes in market liquidity;
federal, state and foreign governmental regulation and legislation; and
the creditworthiness and liquidity and willingness of fuel suppliers/transporters to do business with the Company.

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.


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

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

In the South Central region, NRG has long-term contracts with rural cooperatives that require it to serve all of the cooperatives' requirements at prices that generally reflect the costs of coal-fired generation. During limited peak demand periods, the load requirements of these contract customers exceed the baseload capacity of NRG's coal-fired Big Cajun II plant. During such peak demand periods, NRG employs its intermediate and/or peaking facilities.  Depending upon the then-current gas commodity pricing, NRG's financial returns from its South Central region could be negatively impacted for a limited period if the cost of its intermediate and/or peaking power is at higher prices than can be recovered under the Company's contracts.  

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

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

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

NRG may not have sufficient liquidity to hedge market risks effectively.
The Company is exposed to market risks through its power marketing business, which involves the sale of energy, capacity and related products and the purchase and sale of fuel, transmission services and emission allowances. These market risks include, among other risks, volatility arising from location and timing differences that may be associated with buying and transporting fuel, converting fuel into energy and delivering the energy to a buyer.

NRG undertakes these marketing activities through agreements with various counterparties. Many of the Company's agreements with counterparties include provisions that require the Company to provide guarantees, offset of netting arrangements, letters of credit, a first 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.

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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 the Financial Accounting Standards Board, or FASB, Accounting Standard Codification, or ASC, 815, Derivatives and Hedging, or ASC 815, which requires the Company to record all derivatives on the balance sheet at fair value with changes in the fair value resulting from fluctuations in the underlying commodity prices immediately recognized in earnings, unless the derivative qualifies for cash flow hedge accounting treatment. Whether a derivative qualifies for cash flow hedge accounting treatment depends upon it meeting specific criteria used to determine if the cash flow hedge is and will remain appropriate for the term of the derivative. All economic hedges may not necessarily qualify for cash flow hedge accounting treatment. As a result, the Company's quarterly and annual results are subject to significant fluctuations caused by changes in market prices.

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

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

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

Other companies with which NRG competes with may have greater liquidity, greater access to credit and other financial resources, lower cost structures, more effective risk management policies and procedures, greater ability to incur losses, longer-standing relationships with customers, greater potential for profitability from ancillary services or greater flexibility in the timing of their sale of generation capacity and ancillary services than NRG does.

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


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

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

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

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

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

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

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


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

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

the inability to receive U.S. DOE loan guarantees, funding or cash grants;
delays in obtaining necessary permits and licenses;
the inability to sell down interests in a project or develop successful partnering relationships;
environmental remediation of soil or groundwater at contaminated sites;
interruptions to dispatch at the Company's facilities;
supply interruptions;
work stoppages;
labor disputes;
weather interferences;
unforeseen engineering, environmental and geological problems;
unanticipated cost overruns;
exchange rate risks; and
failure of contracting parties to perform under contracts, including EPC contractors.

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

Furthermore, where the Company has partnering relationships with a third party, the Company is subject to the viability and performance of the third party. The Company's inability to find a replacement contracting party, particularly an EPC contractor, where the original contracting party has failed to perform, could result in the abandonment of the development and/or construction of such project, while the Company could remain obligated on other agreements associated with the project, including PPAs.

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

NRG and its subsidiaries have guaranteed the performance of third parties, which may result in substantial costs in the event of non-performance.
 
NRG and its subsidiaries have issued certain guarantees of the performance of others, which obligate NRG and its subsidiaries to perform in the event that the third parties do not perform. In the event of non-performance by the third parties, NRG could incur substantial cost to fulfill their obligations under these guarantees. Such performance guarantees could have a material impact on the operating results, financial condition, or cash flows of the Company.


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The Company's development programs are subject to financing and public policy risks that could adversely impact NRG's financial performance or result in the abandonment of such development projects.

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

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.

Furthermore, the viability of the Company's renewable development projects are largely contingent on public policy mechanisms including production and investment tax credits, cash grants, loan guarantees, accelerated depreciation tax benefits, renewable portfolio standards, or RPS, and carbon trading plans. These mechanisms have been implemented at the state and federal levels to support the development of renewable generation, demand-side and smart grid, and other clean infrastructure technologies. The availability and continuation of public policy support mechanisms will drive a significant part of the economics and viability of the Company's development program and expansion into clean energy investments.

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.


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

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

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

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 the Company's 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 or which complement the Company's industry. The acquisition of 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, the ability to retain customers 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 FPA are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Except for ERCOT generating facilities and power marketers, all of NRG's non-qualifying facility generating companies and power marketing affiliates in the U.S. make sales of electricity in interstate commerce and are public utilities for purposes of the FPA. The FERC has granted each of NRG's generating and power marketing companies that make sales of electricity outside of ERCOT the authority to sell electricity at market-based rates. The FERC's orders that grant NRG's generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that NRG can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions.

40


In addition, NRG's market-based sales are subject to certain market behavior rules, and if any of NRG's generating and power marketing companies were deemed to have violated one of those rules, they are subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority. If NRG's generating and power marketing companies were to lose their market-based rate authority, such companies would be required to obtain the FERC's acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates NRG charges for power from its facilities.

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

The regulatory environment has undergone significant changes in the last several years due to state and federal policies affecting wholesale and retail competition and the creation of incentives for the addition of large amounts of new renewable generation and, in some cases, transmission. 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, the Company's business prospects and financial results could be negatively impacted.

NRG cannot predict at this time the outcome of the ongoing efforts by the CFTC to implement the Dodd-Frank Act and to increase the regulation of over-the-counter derivatives including those related to energy commodities. The CFTC efforts are seeking, among other things, increased clearing of such derivatives through clearing organizations and the increased standardization of contracts, products, and collateral requirements. Such changes could negatively impact NRG's ability to hedge its portfolio in an efficient, cost-effective manner by, among other things, limiting NRG's ability to utilize liens as collateral and decreasing liquidity in the forward commodity markets. The Company expects that in 2012 the CFTC will clarify the scope of the Dodd-Frank Act and issue final rules concerning a central clearing and execution exemption for derivative end-users, margin requirements for transactions, the definition of a “swap” and other issues that will affect the Company's over-the-counter derivatives trading.

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

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

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

41



While STP maintains property and liability insurance for losses related to nuclear operations, there may be limitations on the amounts and types of insurance commercially available. An accident at STP or another nuclear facility could have a material adverse effect on NRG's financial condition, its operational results, or liquidity as losses may exceed the insurance coverage available and/or may result in the obligation to pay retrospective premium obligations.

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

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

Environmental laws and regulations have generally become more stringent over time, and the Company expects this trend to continue. Regulations currently under revision by the U.S. EPA, including the 316 (b) rule to mitigate impact by once-through cooling, could result in tighter standards or reduced compliance flexibility. While the NRG fleet employs advanced controls and utilizes industry's best practices, new regulations to address tightened National Ambient Air Quality Standards, or NAAQS, limit GHG emissions or restrict ash handling at coal-fired power plants could also further affect plant operations.

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

NRG's GHG emissions for 2011 can be found in Item 1, Business - Environmental Matters. The impact of further legislation or regulation of GHGs on the Company's financial performance will depend on a number of factors, including the level of GHG standards, the extent to which mitigation is required, the applicability of offsets, and the extent to which NRG would be entitled to receive CO2 emissions credits without having to purchase them in an auction or on the open market

The Company operates generating units in Connecticut, Delaware, Maryland, Massachusetts, and New York that are subject to the Regional Greenhouse Gas Initiative, or RGGI. While 2009 through 2011 RGGI CO2 allowance prices have remained low, the impact of RGGI on future power prices (and thus on the Company's financial performance), indirectly through generators seeking to pass through the cost of their CO2 emissions, cannot be predicted.

In addition, under certain conditions, GHG emissions from power plants are subject to existing sections of the CAA including Prevention of Significant Deterioration and New Source Review, or PSD/NSR, and Title V permitting. Implementation practices under the PSD/NSR and GHG performance standards that may be set under Section 111 will determine the extent to which power plant operations are affected over time.

Hazards customary to the power production industry include the potential for unusual weather conditions, which could affect fuel pricing and availability, the Company's route to market or access to customers, i.e. transmission and distribution lines, or critical plant assets. To the extent that climate change contributes to the frequency or intensity of weather related events, NRG's operations and planning process could be impacted.

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

As of December 31, 2011, approximately 63% of NRG's employees at its U.S. generation plants were covered by collective bargaining agreements. In the event that the Company's union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or disruption, NRG would be responsible for procuring replacement labor or the Company could experience reduced power generation or outages. NRG's ability to procure such labor is uncertain. Strikes, work stoppages or the inability to negotiate future collective bargaining agreements on favorable terms could have a material adverse effect on the Company's business, financial condition, results of operations and cash flow. In addition, a number of the Company's employees at NRG's plants are close to retirement. The Company's inability to replace those workers could create potential knowledge and expertise gaps as those workers retire.

42



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 "clean" coal and coal gasification, wind, photovoltaic (solar) cells, energy storage, 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.

Risks that are beyond NRG's control, including but not limited to acts of terrorism or related acts of war, natural disaster, hostile cyber intrusions or other catastrophic events 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. Hostile cyber intrusions, including those targeting information systems as well as electronic control systems used at the generating plants and for the distribution systems, could severely disrupt business operations and result in loss of service to customers, as well as significant expense to repair security breaches or system damage. Any such environmental repercussions or disruption could result in a significant decrease in revenues or significant reconstruction or remediation costs, beyond what could be recovered through insurance policies which could have a material adverse effect on the Company's financial condition, results of operations and cash flow.

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

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

increasing NRG's vulnerability to general economic and industry conditions;
requiring a substantial portion of NRG's cash flow from operations to be dedicated to the payment of principal and interest on its indebtedness, therefore reducing NRG's ability to pay dividends to holders of its preferred or common stock or to use its cash flow to fund its operations, capital expenditures and future business opportunities;
limiting NRG's ability to enter into long-term power sales or fuel purchases which require credit support;
exposing NRG to the risk of increased interest rates because certain of its borrowings, including borrowings under its new senior secured credit facility are at variable rates of interest;
limiting NRG's ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; and
limiting NRG's ability to adjust to changing market conditions and placing it at a competitive disadvantage compared to its competitors who have less debt.

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


43


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:

general economic and capital market conditions;
credit availability from banks and other financial institutions;
investor confidence in NRG, its partners and the regional wholesale power markets;
NRG's financial performance and the financial performance of its subsidiaries;
NRG's level of indebtedness and compliance with covenants in debt agreements;
maintenance of acceptable credit ratings;
cash flow; and
provisions of tax and securities laws that may impact raising capital.

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

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

In accordance with ASC 350, Intangibles — Goodwill and Other, or ASC 350, 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.

Volatile power supply costs and demand for power could adversely affect the financial performance of NRG's Retail Businesses.

Although NRG is the primary provider of Reliant Energy's supply requirements, Reliant Energy purchases a significant portion of its supply requirements from third parties. As a result, Reliant Energy's financial performance depends on its ability to obtain adequate supplies of electric generation from third parties at prices below the prices it charges its customers. Consequently, the Company's earnings and cash flows could be adversely affected in any period in which Reliant Energy's power supply costs rise at a greater rate than the rates it charges to customers. The price of power supply purchases associated with Reliant Energy's energy commitments can be different than that reflected in the rates charged to customers due to, among other factors:

varying supply procurement contracts used and the timing of entering into related contracts;
subsequent changes in the overall price of natural gas;
daily, monthly or seasonal fluctuations in the price of natural gas relative to the 12-month forward prices;
transmission constraints and the Company's ability to move power to its customers; and
changes in market heat rate (i.e., the relationship between power and natural gas prices).

The Company's earnings and cash flows could also be adversely affected in any period in which the demand for power significantly varies from the forecasted supply, which could occur due to, among other factors, weather events, competition and economic conditions.

Significant events beyond the Company's control, such as hurricanes and other weather-related problems or acts of terrorism, could cause a loss of load and customers and thus have a material adverse effect on the Company's Retail Businesses.

The uncertainty associated with events beyond the Company's control, such as significant weather events and the risk of future terrorist activity, could cause a loss of load and customers and may affect the Company's results of operations and financial condition in unpredictable ways. In addition, significant weather events or terrorist actions could damage or shut down the power transmission and distribution facilities upon which the retail business is dependent. Power supply may be sold at a loss if these events cause a significant loss of retail customer load.

44


The Company's Retail Businesses may lose a significant number of retail customers due to competitive marketing activity by other retail electricity provider which could adversely affect the financial performance of NRG's Retail Businesses.
The Retail Businesses face competition for customers. Competitors may offer lower prices and other incentives, which may attract customers away from the Retail Businesses. In some retail electricity markets, the principal competitor may be the incumbent retail electricity provider. The incumbent retail electricity provider has the advantage of long-standing relationships with its customers, including well-known brand recognition. Furthermore, the Retail Businesses may face competition from a number of other energy service providers, other energy industry participants, or nationally branded providers of consumer products and services who may develop businesses that will compete with NRG and its Retail Businesses.
The Company's Retail Businesses are subject to the risk that sensitive customer data may be compromised, which could result in an adverse impact to its reputation and/or the results of operations of the Retail Businesses.
The Retail Businesses require access to sensitive customer data in the ordinary course of business. Examples of sensitive customer data are names, addresses, account information, historical electricity usage, expected patterns of use, payment history, credit bureau data, credit and debit card account numbers, drivers license numbers, social security numbers and bank account information. The Retail Businesses may need to provide sensitive customer data to vendors and service providers who require access to this information in order to provide services, such as call center operations, to the retail businesses. If a significant breach occurred, the reputation of NRG and the Retail Businesses may be adversely affected, customer confidence may be diminished, or NRG and the Retail Businesses may be subject to legal claims, any of which may contribute to the loss of customers and have a negative impact on the business and/or results of operations.




45


Cautionary Statement Regarding Forward Looking Information

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

General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel;
Volatile power supply costs and demand for power;
Hazards customary to the power production industry and power generation operations such as fuel and electricity price volatility, unusual weather conditions, catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that NRG may not have adequate insurance to cover losses as a result of such hazards;
The effectiveness of NRG's risk management policies and procedures, and the ability of NRG's counterparties to satisfy their financial commitments;
Counterparties' collateral demands and other factors affecting NRG's liquidity position and financial condition;
NRG's ability to operate its businesses efficiently, manage capital expenditures and costs tightly, and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;
NRG's ability to enter into contracts to sell power and procure fuel on acceptable terms and prices;
The liquidity and competitiveness of wholesale markets for energy commodities;
Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws and increased regulation of carbon dioxide and other greenhouse gas emissions;
Price mitigation strategies and other market structures employed by ISOs or RTOs that result in a failure to adequately compensate NRG's generation units for all of its costs;
NRG's ability to borrow additional funds and access capital markets, as well as NRG's substantial indebtedness and the possibility that NRG may incur additional indebtedness going forward;
NRG's ability to receive Federal loan guarantees or cash grants to support development projects;
Operating and financial restrictions placed on NRG and its subsidiaries that are contained in the indentures governing NRG's outstanding notes, in NRG's Senior Credit Facility, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;
NRG's ability to implement its strategy of developing and building new power generation facilities, including new solar projects;
NRG's ability to implement its econrg strategy of finding ways to meet the challenges of climate change, clean air and protecting natural resources while taking advantage of business opportunities;
NRG's ability to implement its FORNRG strategy of increasing the return on invested capital through operational performance improvements and a range of initiatives at plants and corporate offices to reduce costs or generate revenues;
NRG's ability to achieve its strategy of regularly returning capital to stockholders;
NRG's ability to maintain retail market share;
NRG's ability to successfully evaluate investments in new business and growth initiatives;
NRG's ability to successfully integrate and manage any acquired businesses; and
NRG's ability to develop and maintain successful partnering relationships.

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

Item 1B — Unresolved Staff Comments

None.

46



Item 2 — Properties

Listed below are descriptions of NRG's interests in facilities, operations and/or projects owned as of December 31, 2011. The MW figures provided represent nominal summer net megawatt capacity of power generated as adjusted for the Company's ownership position excluding capacity from inactive/mothballed units as of December 31, 2011. The following table summarizes NRG's power production and cogeneration facilities by region:
Name and Location of Facility
Power Market
 
% Owned
 
Net
Generation
Capacity (MW) (a)
 
Primary
Fuel-type
Texas Region:
 
 
 
 
 
 
 
Cedar Bayou, Baytown, TX
ERCOT
 
100.0
 
1,495

 
Natural Gas
Cedar Bayou 4, Baytown, TX
ERCOT
 
50.0
 
260

 
Natural Gas
Elbow Creek Wind Farm, Howard County, TX
ERCOT
 
100.0
 
125

 
Wind
Greens Bayou, Houston, TX
ERCOT
 
100.0
 
355

 
Natural Gas
Langford Wind Farm, Christoval, TX
ERCOT
 
100.0
 
150

 
Wind
Limestone, Jewett, TX
ERCOT
 
100.0
 
1,690

 
Coal
San Jacinto, LaPorte, TX
ERCOT
 
100.0
 
160

 
Natural Gas
Sherbino Wind Farm, Pecos County, TX
ERCOT
 
50.0
 
75

 
Wind
South Texas Project, Bay City, TX (b)
ERCOT
 
44.0
 
1,175

 
Nuclear
South Trent Wind Farm, Sweetwater, TX
ERCOT
 
100.0
 
100

 
Wind
S. R. Bertron, Deer Park, TX
ERCOT
 
100.0
 
470

 
Natural Gas
T. H. Wharton, Houston, TX
ERCOT
 
100.0
 
1,025

 
Natural Gas
W. A. Parish, Thompsons, TX (c)
ERCOT
 
100.0
 
2,490

 
Coal
W. A. Parish, Thompsons, TX (c)
ERCOT
 
100.0
 
1,175

 
Natural Gas
Northeast Region:
 
 
 
 
 
 
 
Arthur Kill, Staten Island, NY
NYISO
 
100.0
 
865

 
Natural Gas
Astoria Gas Turbines, Queens, NY
NYISO
 
100.0
 
550

 
Natural Gas
Conemaugh, New Florence, PA
PJM
 
3.7
 
65

 
Coal
Connecticut Jet Power, CT (four sites)
ISO-NE
 
100.0
 
140

 
Oil
Devon, Milford, CT
ISO-NE
 
100.0
 
135

 
Oil
GenConn Devon, Milford, CT
ISO-NE
 
50.0
 
95

 
Oil
Dunkirk, NY
NYISO
 
100.0
 
530

 
Coal
Huntley, Tonawanda, NY
NYISO
 
100.0
 
380

 
Coal
Indian River, Millsboro, DE (d)
PJM
 
100.0
 
580

 
Coal
Keystone, Shelocta, PA
PJM
 
3.7
 
65

 
Coal
Middletown, CT
ISO-NE
 
100.0
 
770

 
Oil
GenConn Middletown, CT
ISO-NE
 
50.0
 
95

 
Oil
Montville, Uncasville, CT
ISO-NE
 
100.0
 
500

 
Oil
Norwalk Harbor, So. Norwalk, CT
ISO-NE
 
100.0
 
340

 
Oil
Oswego, NY
NYISO
 
100.0
 
1,635

 
Oil
Vienna, MD
PJM
 
100.0
 
170

 
Oil
South Central Region:
 
 
 
 
 
 
 
Bayou Cove, Jennings, LA
SERC-Entergy
 
100.0
 
300

 
Natural Gas
Big Cajun I, Jarreau, LA
SERC-Entergy
 
100.0
 
430

 
Natural Gas
Big Cajun II, New Roads, LA (e)
SERC-Entergy
 
86.0
 
1,495

 
Coal
Cottonwood, Deweyville, TX
SERC-Entergy
 
100.0
 
1,265

 
Natural Gas
Rockford I, IL
PJM
 
100.0
 
305

 
Natural Gas

47


Rockford II, IL
PJM
 
100.0
 
155

 
Natural Gas
Sterlington, LA
SERC-Entergy
 
100.0
 
175

 
Natural Gas
West Region:
 
 
 
 
 
 
 
Avenal, CA
CAISO
 
50.0
 
25

 
Solar
Blythe, CA
CAISO
 
100.0
 
20

 
Solar
El Segundo Power, CA
CAISO
 
100.0
 
670

 
Natural Gas
Encina, Carlsbad, CA
CAISO
 
100.0
 
965

 
Natural Gas
Long Beach, CA
CAISO
 
100.0
 
260

 
Natural Gas
Roadrunner, Santa Teresa, NM
EPE
 
100.0
 
20

 
Solar
Saguaro Power Co., Henderson, NV
WECC
 
50.0
 
45

 
Natural Gas
San Diego Combustion Turbines, CA (four sites)
CAISO
 
100.0
 
190

 
Natural Gas
International Region:
 
 
 
 
 
 
 
Gladstone Power Station, Queensland, Australia
Enertrade/Boyne Smelter
 
37.5
 
605

 
Coal
Schkopau Power Station, Germany
Vattenfall Europe
 
41.9
 
400

 
Coal
(a)
Actual capacity can vary depending on factors including weather conditions, operational conditions, and other factors. Additionally, ERCOT requires periodic demonstration of capability, and the capacity may vary individually and in the aggregate from time to time.
(b)
Generation capacity figure consists of the Company's 44% individual interest in the two units at STP.
(c)
W.A. Parish has nine units, four of which are baseload coal-fired units and five of which are natural gas-fired units.
(d)
Indian River Unit 1 was retired May 31, 2011, and Indian River Unit 3 will be retired by December 31, 2013.
(e)
Units 1 and 2 owned 100.0%, Unit 3 owned 58.0%.

Thermal Facilities

The Company's thermal businesses in Pittsburgh, Harrisburg and San Francisco are regulated by their respective state's Public Utility Commission. The other thermal businesses are subject to contract terms with their customers.

The following table summarizes NRG's thermal steam and chilled water facilities as of December 31, 2011:

Name and Location of Facility
% Owned
 
Thermal Energy Purchaser
 
Megawatt
Thermal
Equivalent
Capacity (MWt)
 
Generating
Capacity
NRG Energy Center Minneapolis, MN
100.0

 
Approx. 100 steam and 50 chilled water customers
 
334
141

 
Steam: 1,140 MMBtu/hr.
Chilled Water: 40,200 tons
NRG Energy Center San Francisco, CA
100.0

 
Approx 170 steam customers
 
133

 
Steam: 454 MMBtu/Hr.
NRG Energy Center Harrisburg, PA
100.0

 
Approx 210 steam and 3 chilled water customers
 
129
8

 
Steam: 440 MMBtu/hr.
Chilled water: 2,400 tons
NRG Energy Center Phoenix, AZ
100.0

 
Approx 30 chilled water customers
 
90

 
Chilled water: 25,600 tons
NRG Energy Center Pittsburgh, PA
100.0

 
Approx 25 steam and 25 chilled water customers
 
87
45

 
Steam: 296 MMBtu/hr.
Chilled water: 12,920 tons
NRG Energy Center San Diego, CA
100.0

 
Approx 20 chilled water customers
 
26

 
Chilled water: 7,425 tons
Camas Power Boiler Camas, WA
100.0

 
Georgia Pacific Group
 
59

 
Steam: 200 MMBtu/hr.
NRG Energy Center Dover, DE
100.0

 
Kraft Foods Inc. and Proctor & Gamble Company
 
56

 
Steam: 190 MMBtu/hr.

The following table summarizes NRG's thermal power generation facilities, as of December 31, 2011:

Name and Location of Facility
Power Market/
Zone
 
% Owned
 
Generation
Capacity (MW)
 
Primary
Fuel Type
Paxton Creek Cogeneration Harrisburg, PA
PJM / East
 
100.0

 
12

 
Natural Gas
Dover Cogeneration, DE
PJM / West
 
100.0

 
104

 
Coal
Princeton Hospital, NJ
PJM/East
 
100.0

 
5

 
Natural Gas


48


Other Properties

NRG owns 30 MW of Distributed Solar facilities at various locations throughout the United States, concentrated primarily in the West Region.

In addition, NRG owns several real properties and facilities relating to its generation assets, other vacant real property unrelated to the Company's generation assets, interests in construction projects, and properties not used for operational purposes. NRG believes it has satisfactory title to its plants and facilities in accordance with standards generally accepted in the electric power industry, subject to exceptions that, in the Company's opinion, would not have a material adverse effect on the use or value of its portfolio.

NRG leases its corporate offices at 211 Carnegie Center, Princeton, New Jersey, its Reliant Energy, Green Mountain Energy, and Energy Plus offices and call centers, and various other office space.

49




Item 3 — Legal Proceedings

Public Utilities Commission of the State of California v. Long-Term Sellers of Long-Term Contracts to the California Department of Water Resources, FERC Docket No. EL02-60 et al. — This matter concerns, among other contracts and other defendants, the California Department of Water Resources, or CDWR, and its wholesale power contract with subsidiaries of WCP (Generation) Holdings, Inc., or WCP. The case originated with a February 2002 complaint filed by the State of California alleging that many parties, including WCP subsidiaries, overcharged the State of California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint demanded that the FERC, abrogate the CDWR contract and sought refunds associated with revenues collected under the contract. In 2003, the FERC rejected this complaint, denied rehearing, and the case was appealed to the U.S. Court of Appeals for the Ninth Circuit where oral argument was held on December 8, 2004. On December 19, 2006, the Ninth Circuit decided that in the FERC's review of the contracts at issue, the FERC could not rely on the Mobile-Sierra standard presumption of just and reasonable rates, where such contracts were not reviewed by the FERC with full knowledge of the then existing market conditions. WCP and others sought review by the U.S. Supreme Court. WCP's appeal was not selected, but instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June 26, 2008, the Supreme Court ruled: (i) that the Mobile-Sierra public interest standard of review applied to contracts made under a seller's market-based rate authority; (ii) that the public interest “bar” required to set aside a contract remains a very high one to overcome; and (iii) that the Mobile-Sierra presumption of contract reasonableness applies when a contract is formed during a period of market dysfunction unless (a) such market conditions were caused by the illegal actions of one of the parties or (b) the contract negotiations were tainted by fraud or duress. In this related case, the U.S. Supreme Court affirmed the Ninth Circuit's decision agreeing that the case should be remanded to the FERC to clarify the FERC's 2003 reasoning regarding its rejection of the original complaint relating to the financial burdens under the contracts at issue and to alleged market manipulation at the time these contracts were formed. As a result, the U.S. Supreme Court then reversed and remanded the WCP CDWR case to the Ninth Circuit for treatment consistent with its June 26, 2008, decision in the related case. On October 20, 2008, the Ninth Circuit asked the parties in the remanded CDWR case, including WCP and the FERC, whether that Court should answer a question the U.S. Supreme Court did not address in its June 26, 2008, decision; whether the Mobile-Sierra doctrine applies to a third-party that was not a signatory to any of the wholesale power contracts, including the CDWR contract, at issue in that case. Without answering that reserved question, on December 4, 2008, the Ninth Circuit vacated its prior opinion and remanded the WCP CDWR case back to the FERC for proceedings consistent with the U.S. Supreme Court's June 26, 2008, decision.

On December 15, 2008, WCP and the other seller-defendants filed with the FERC a Motion for Order Governing Proceedings on Remand. On January 14, 2009, the Public Utilities Commission of the State of California filed an Answer and Cross Motion for an Order Governing Procedures on Remand and on January 28, 2009, WCP and the other seller-defendants filed their reply. At this time, the FERC has not acted on remand.

At this time, while NRG cannot predict with certainty whether WCP will be required to make refunds for rates collected under the CDWR contract or estimate the range of any such possible refunds, a reconsideration of the CDWR contract by the FERC with a resulting order mandating significant refunds could have a material adverse impact on NRG's financial position, statement of operations, and statement of cash flows. As part of the 2006 acquisition of Dynegy's 50% ownership interest in WCP, WCP and NRG assumed responsibility for any risk of loss arising from this case, unless any such loss was deemed to have resulted from certain acts of gross negligence or willful misconduct on the part of Dynegy, in which case any such loss would be shared equally between WCP and Dynegy.

On January 14, 2010, the U.S. Supreme Court issued its decision in an unrelated proceeding involving the Mobile-Sierra doctrine that will affect the standard of review applied to the CDWR contract on remand before the FERC. In NRG Power Marketing v. Maine Public Utilities Commission, the Supreme Court held that the Mobile-Sierra presumption regarding the reasonableness of contract rates does not depend on the identity of the complainant who seeks a FERC investigation/refund.


50


United States of America v. Louisiana Generating, LLC., U.S.D.C Middle District of Louisiana, Civil Action No. 09-100-RET-CN (filed February 11, 2009) — On February 11, 2009, the U.S. DOJ, acting at the request of the U.S. Environmental Protection Agency, or U.S. EPA, commenced a lawsuit against Louisiana Generating, LLC, or LaGen, in the United States District Court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant. This is the same matter for which Notices of Violation, or NOVs, were issued to LaGen on February 15, 2005, and on December 8, 2006. Specifically, it is alleged that in the late 1990's, several years prior to NRG's acquisition of the Big Cajun II power plant from the Cajun Electric bankruptcy and several years prior to the NRG bankruptcy, modifications were made to Big Cajun II Units 1 and 2 by the prior owners without appropriate or adequate permits and without installing and employing the best available control technology, or BACT, to control emissions of nitrogen oxides and/or sulfur dioxides. The relief sought in the complaint includes a request for an injunction to: (i) preclude the operation of Units 1 and 2 except in accordance with the CAA; (ii) order the installation of BACT on Units 1 and 2 for each pollutant subject to regulation under the CAA; (iii) obtain all necessary permits for Units 1 and 2; (iv) order the surrender of emission allowances or credits; (v) conduct audits to determine if any additional modifications have been made which would require compliance with the CAA's Prevention of Significant Deterioration program; (vi) award to the Department of Justice its costs in prosecuting this litigation; and (vii) assess civil penalties of up to $27,500 per day for each CAA violation found to have occurred between January 31, 1997, and March 15, 2004, up to $32,500 for each CAA violation found to have occurred between March 15, 2004, and January 12, 2009, and up to $37,500 for each CAA violation found to have occurred after January 12, 2009.

On April 27, 2009, LaGen filed an objection in the Cajun Electric Cooperative Power, Inc.'s bankruptcy proceeding in the U.S. Bankruptcy Court for the Middle District of Louisiana to seek to prevent the bankruptcy from closing. LaGen also filed a complaint, or adversary proceeding, in the same bankruptcy proceeding, seeking a judgment that: (i) it did not assume liability from Cajun Electric for any claims or other liabilities under environmental laws with respect to Big Cajun II that arose, or are based on activities that were undertaken, prior to the closing date of the acquisition; (ii) it is not otherwise the successor to Cajun Electric with respect to environmental liabilities arising prior to the acquisition; and (iii) Cajun Electric and/or the Bankruptcy Trustee are exclusively liable for any of the violations alleged in the February 11, 2009, lawsuit to the extent that such claims are determined to have merit. On April 15, 2010, the bankruptcy court signed an order granting LaGen's stipulation of voluntary dismissal without prejudice of the adversary proceeding. The bankruptcy proceeding has since closed.

On August 24, 2009, LaGen filed a motion to dismiss this lawsuit, and on September 25, 2009, the U.S. DOJ filed its opposition to the motion. Thereafter, on February 18, 2010, the Louisiana Department of Environmental Quality, or LDEQ, filed a motion to intervene in the above lawsuit and a complaint against LaGen for alleged violations of Louisiana's Prevention o