10-K 1 a201410-k.htm 10-K 2014 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, 2014.
 
 
 
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 $9,508,294,816 based on the closing sale price of $37.20 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 January 31, 2015
Common Stock, par value $0.01 per share
 
337,695,251
Documents Incorporated by Reference:
Portions of the Registrant's definitive Proxy Statement relating to its 2015 Annual Meeting of Stockholders
are incorporated by reference into Part III of this Annual Report on Form 10-K
 
 
 
 
 

1

                                                                                     

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:
AB32
 
California GHG Allowance Program
AEP
 
American Electric Power
ARO
 
Asset Retirement Obligation
ARRA
 
American Recovery and Reinvestment Act of 2009
ASC
 
The FASB Accounting Standards Codification, which the FASB established as the source of authoritative U.S. GAAP
ASU
 
Accounting Standards Updates – updates to the ASC
AZNMSN
 
Arizona, New Mexico and Southern Nevada
B2B
 
Business-to-business, which includes demand response, commodity sales, energy efficiency and energy management services
BACT
 
Best Available Control Technology
Baseload
 
Units expected to satisfy minimum baseload requirements of the system and produce electricity at an essentially constant rate and run continuously
BETM
 
Boston Energy Trading and Marketing LLC
BTU
 
British Thermal Unit
Buffalo Bear
 
Buffalo Bear, LLC, the operating subsidiary of Tapestry Wind LLC, which owns the Buffalo Bear project
CAA
 
Clean Air Act
CAIR
 
Clean Air Interstate Rule
CAISO
 
California Independent System Operator
Capital Allocation Program
 
NRG's plan of allocating capital between debt reduction, reinvestment in the business, investment in acquisition opportunities, share repurchases and shareholder dividends
CCF
 
Carbon Capture Facility
CCPI
 
Clean Coal Power Initiative
CDWR
 
California Department of Water Resources
CenterPoint
 
CenterPoint Energy Houston Electric, LLC
C&I
 
Commercial, industrial and governmental/institutional
CFTC
 
U.S. Commodity Futures Trading Commission
CO2
 
Carbon Dioxide
CPS
 
Combined Pollutant Standard
CPUC
 
California Public Utilities Commission
CSAPR
 
Cross-State Air Pollution Rule
CWA
 
Clean Water Act
Discrete customers
 
Customers measured by unit sales of one-time products or services, such as connected home thermostats, portable solar products and portable battery solutions
Distributed Solar
 
Solar power projects 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
Dodd-Frank Act
 
The Dodd-Frank Wall Street Reform and Consumer Protection Act
Dominion
 
Dominion Resources, Inc.
DSU
 
Deferred Stock Unit
Dunkirk Power
 
Dunkirk Power LLC
El Segundo Energy Center
 
NRG West Holdings LLC, the subsidiary of Natural Gas Repowering LLC, which owns the El Segundo Energy Center project
EME
 
Edison Mission Energy
Energy Plus Holdings
 
Energy Plus Holdings LLC
EPA
 
U.S. Environmental Protection Agency

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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
ESPS
 
Existing Source Performance Standards
EWG
 
Exempt Wholesale Generator
Exchange Act
 
The Securities Exchange Act of 1934, as amended
FASB
 
Financial Accounting Standards Board
FCM
 
Forward Capacity Market
FERC
 
Federal Energy Regulatory Commission
FFB
 
Federal Financing Bank
FPA
 
Federal Power Act
FRCC
 
Florida Reliability Coordinating Council
Fresh Start
 
Reporting requirements as defined by ASC-852, Reorganizations
GenConn
 
GenConn Energy LLC
GenOn
 
GenOn Energy, Inc.
GenOn Americas Generation
 
GenOn Americas Generation, LLC
GenOn Americas Generation Senior Notes
 
GenOn Americas Generation's $850 million outstanding unsecured senior notes consisting of $450 million of 8.5% senior notes due 2021 and $400 million of 9.125% senior notes due 2031
GenOn Mid-Atlantic
 
GenOn Mid-Atlantic, LLC and, except where the context indicates otherwise, its subsidiaries, which include the coal generation units at two generating facilities under operating leases
GenOn Senior Notes
 
GenOn's $2.0 billion outstanding unsecured senior notes consisting of $725 million of 7.875% senior notes due 2017, $675 million of 9.5% senior notes due 2018, and $550 million of 9.875% senior notes due 2020
GHG
 
Greenhouse Gases
Goal Zero
 
Goal Zero LLC
Green Mountain Energy
 
Green Mountain Energy Company
GWh
 
Gigawatt Hour
HAP
 
Hazardous Air Pollutant
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
High Desert
 
TA - High Desert, LLC, the operating subsidiary of NRG Solar Mayfair LLC, which owns the High Desert project
IL CPS
 
Illinois Combined Pollutant Standard
ISO
 
Independent System Operator, also referred to as RTOs
ISO-NE
 
ISO New England Inc.
ITC
 
Investment Tax Credit
Kansas South
 
NRG Solar Kansas South LLC, the operating subsidiary of NRG Solar Kansas South Holdings LLC, which owns the RE Kansas South project
kWh
 
Kilowatt-hour
LaGen
 
Louisiana Generating LLC
Laredo Ridge
 
Laredo Ridge Wind, LLC, the operating subsidiary of Mission Wind Laredo, LLC, which owns the Laredo Ridge project
LIBOR
 
London Inter-Bank Offered Rate
LTIPs
 
Collectively, the NRG Long-Term Incentive Plan and the NRG GenOn Long-Term Incentive Plan
LSEs
 
Load Serving Entities
Marsh Landing
 
NRG Marsh Landing, LLC (formerly known as GenOn Marsh Landing, LLC)

4

                                                                                     

Mass
 
Residential and Small Business
MATS
 
Mercury and Air Toxics Standards
MDE
 
Maryland Department of the Environment
Merger
 
The merger completed on December 14, 2012 by NRG and GenOn pursuant to the Merger Agreement
Merger Agreement
 
The agreement by and among NRG, GenOn and Plus Merger Corporation, dated as of July 20, 2012
MISO
 
Midcontinent Independent System Operator, Inc.
MMBtu
 
Million British Thermal Units
MOPR
 
Minimum Offer Price Rule
MSU
 
Market Stock Unit
MVA
 
Megavolt Ampere
MW
 
Megawatt
MWh
 
Saleable megawatt hour net of internal/parasitic load megawatt-hour
MWt
 
Megawatts Thermal Equivalent
NAAQS
 
National Ambient Air Quality Standards
NEPGA
 
New England Power Generators Association
NERC
 
North American Electric Reliability Corporation
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.
NJDEP
 
New Jersey Department of Environmental Protection
NOx
 
Nitrogen Oxide
NOL
 
Net Operating Loss
NOV
 
Notice of Violation
NPNS
 
Normal Purchase Normal Sale
NQSO
 
Non-Qualified Stock Option
NRC
 
U.S. Nuclear Regulatory Commission
NRG GenOn LTIP
 
NRG 2010 Stock Plan for GenOn Employees (formerly the GenOn Energy, Inc. 2010 Omnibus Incentive Plan, which was assumed by NRG in connection with the Merger)
NRG LTIP
 
NRG Long-Term Incentive Plan
NRG Yield
 
Reporting segment including the following projects: Alpine, Alta Wind, Avenal, Avra Valley, AZ DG Solar, Blythe, Borrego, CVSR, El Segundo Energy Center, GenConn, High Desert, Kansas South, Marsh Landing, PFMG DG Solar, Roadrunner, South Trent and the Thermal Business.
NRG Yield Convertible Notes
 
$345 million aggregate principal amount of 3.50% Convertible Senior Notes due 2019 issued by NRG Yield, Inc.
NRG Yield, Inc.
 
NRG Yield, Inc., the owner of 44.7% of NRG Yield LLC with a controlling interest, and issuer of publicly held shares of Class A common stock
NRG Yield LLC
 
NRG Yield LLC, which owns, through its wholly owned subsidiary, NRG Yield Operating LLC, all of the assets contributed to NRG Yield LLC in connection with the initial public offering of Class A common stock of NRG Yield, Inc.
NSPS
 
New Source Performance Standards
NSR
 
New Source Review
Nuclear Decommissioning Trust Fund
 
NRG's nuclear decommissioning trust fund assets, which are for the Company's portion of the decommissioning of the STP, units 1 & 2
NYISO
 
New York Independent System Operator

5

                                                                                     

NYSPSC
 
New York State Public Service Commission
OCI
 
Other Comprehensive Income
PADEP
 
Pennsylvania Department of Environmental Protection
Peaking
 
Units expected to satisfy demand requirements during the periods of greatest or peak load on the system
PG&E
 
Pacific Gas & Electric
Pinnacle
 
Pinnacle Wind, LLC, the operating subsidiary of Tapestry Wind LLC, which owns the Pinnacle project
PJM
 
PJM Interconnection, LLC
PM
 
Particulate Matter
PPA
 
Power Purchase Agreement
PSD
 
Prevention of Significant Deterioration
PTC
 
Production Tax Credit
PU
 
Performance Unit
PUCT
 
Public Utility Commission of Texas
PUHCA
 
Public Utility Holding Company Act of 2005
Pure Energies
 
Pure Energies Group Inc.
PURPA
 
Public Utility Regulatory Policies Act of 1978
QF
 
Qualifying Facility under PURPA
RCRA
 
Resource Conservation and Recovery Act of 1976
RDS
 
Roof Diagnostics Solar
Recurring customers
 
Customers that subscribe to one or more recurring services, such as electricity, natural gas and protection products, the majority of which are retail electricity customers in Texas and the Northeast
Reliant Energy
 
Reliant Energy Retail Services, LLC
Repowering
 
Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility to achieve a substantial emissions reduction, increase facility capacity and improve system efficiency
Revolving Credit Facility
 
The Company's $2.5 billion revolving credit facility due 2018, a component of the Senior Credit Facility
RGGI
 
Regional Greenhouse Gas Initiative
Right of First Offer Agreement
 
Right of First Offer Agreement by and between NRG Energy, Inc. and NRG Yield, Inc.
RMR
 
Reliability Must-Run
RPM
 
Reliability Pricing Model
RPS
 
Renewable Portfolio Standards
RSS
 
Reliability Support Service
RSU
 
Restricted Stock Unit
RTO
 
Regional Transmission Organization
Schkopau
 
Kraftwerk Schkopau Betriebsgesellschaft mbH
SCR
 
Selective Catalytic Reduction Control System
SEC
 
U.S. Securities and Exchange Commission
Securities Act
 
The Securities Act of 1933, as amended
SEG
 
Saale Energie GmbH
Senior Credit Facility
 
NRG's senior secured facility, comprised of the Term Loan Facility and the Revolving Credit Facility
SIFMA
 
Securities Industry and Financial Markets Association
Senior Notes
 
The Company's $6.4 billion outstanding unsecured senior notes consisting of $1.1 billion of 7.625% senior notes due 2018, $1.1 billion of 8.25% senior notes due 2020, $1.1 billion of 7.875% senior notes due 2021, $1.1 billion of 6.25% senior notes due 2022, $990 million of 6.625% senior notes due 2023 and $1.0 billion of 6.25% senior notes due 2024

6

                                                                                     

SERC
 
Southeastern Electric Reliability Council
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
Taloga
 
Taloga Wind, LLC, the operating subsidiary of Tapestry Wind LLC, which owns the Taloga project
Term Loan Facility
 
The Company's $2.0 billion term loan facility due 2018, a component of the Senior Credit Facility
Texas Genco
 
Texas Genco LLC
Thermal Business
 
NRG Yield’s thermal business, which consists of thermal infrastructure assets that provide steam, hot water and/or chilled water, and in some instances electricity, to commercial businesses, universities, hospitals and governmental units
TSR
 
Total Shareholder Return
TWh
 
Terawatt Hour
U.S.
 
United States of America
U.S. DOE
 
U.S. Department of Energy
U.S. GAAP
 
Accounting principles generally accepted in the U.S.
Utility Scale Solar
 
Solar power projects, typically 20 MW or greater in size (on an alternating current basis), that are interconnected into the transmission or distribution grid to sell power at a wholesale level
VaR
 
Value at Risk
VIE
 
Variable Interest Entity
Walnut Creek
 
NRG Walnut Creek, LLC, the operating subsidiary of WCEP Holdings, LLC, which owns the Walnut Creek project
WCP
 
WCP (Generation) Holdings, Inc.
WECC
 
Western Electricity Coordinating Council
Yield Operating
 
NRG Yield Operating LLC

7

                                                                                     

PART I
Item 1 — Business
General
NRG Energy, Inc., or NRG or the Company, is a competitive power company that produces, sells and delivers energy and energy products and services in major competitive power markets in the U.S. while positioning itself as a leader in the way residential, industrial and commercial consumers think about and use energy products and services. NRG is responding to a consumer-driven change to the U.S. energy industry by offering cleaner, smarter and ultimately more portable energy while enabling personal energy choice, building on the strength of one of the nation’s largest and most diverse competitive power generation portfolios. The Company owns and operates approximately 52,000 MWs of generation; engages in the trading of wholesale energy, capacity and related products around those generation assets; transacts in and trades fuel and transportation services; and directly sells energy, services, and innovative, sustainable products and services to retail customers under the name “NRG” and various other retail brand names owned by NRG. NRG was incorporated as a Delaware corporation on May 29, 1992.
NRG's Business Strategy
NRG's strategy, summarized in “Enhance Generation, Expand Retail and Go Green while engaging in Smart Capital Allocation” is 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, low carbon and portable energy solutions individualized for the benefit of the end use energy consumer. This strategy is intended to enable the Company to achieve substantial sustainable growth at reasonable margins while de-risking the Company in terms of reduced and mitigated exposure both to "environmental risk" and cyclical commodity price risk. At the same time, the Company's relentless commitment to safety for its employees, customers and partners continues unabated.
The Company believes that the U.S. energy industry is going to be increasingly impacted by the long-term societal trend towards sustainability, which is both generational and irreversible. Moreover, it further believes the information technology driven revolution, increasingly wireless and thus portable, has enabled greater and easier personal choice in other sectors of the consumer economy, will do the same in the U.S. energy sector over the years to come. Finally, NRG believes that the aging and static transmission and distribution infrastructure of the national grid is becoming increasingly inadequate in the face of the more extreme weather demands of the 21st century. As a result, the Company expects energy consumers to secure increased personal control over their energy choices in the future. Nevertheless, as the Company shifts to respond to these trends that are playing out over time, the Company's immediate imperative every day remains to serve its customers and the markets in which it operates with safe, affordable, reliable and increasingly sustainable power.
To address these trends and effectuate the Company’s strategy, NRG is focused on: (i) excellence in operating performance of its existing assets including repowering its power generation assets at premium sites and optimal hedging of generation assets and retail load operations; (ii) serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels with a variety of retail energy products and services differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs; (iii) investing in, and deploying, alternative energy technologies both in its wholesale portfolio through its wind and solar portfolio and, particularly, in and around its retail businesses and its customers as it transforms this part of its business into a technology-driven provider of retail energy services; and (iv) 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; including pursuing selective acquisitions, joint ventures, divestitures and investments.
To further enhance the Company’s strategy, the Company has reorganized its businesses and personnel on the basis of their key target customer segments. The new businesses include NRG Business, NRG Home and NRG Renew. In addition, NRG Carbon 360 and NRG eVgo are two distinct businesses that have dedicated management and are organized separately within NRG because of their distinct capital structure, success metrics and competitive environment but are supportive of and closely coordinated with NRG's core businesses. These five companies, plus NRG Yield, are described in detail below.

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NRG Business
NRG Business consists of the Company’s wholesale operations including plant operations, commercial operations, EPC, energy services and other critical related functions. NRG has traditionally referred to this business as its wholesale power generation business. In addition to the traditional functions from NRG’s wholesale power generation business, NRG Business also includes NRG’s B2B solutions, which include demand response, commodity sales, energy efficiency and energy management services, and NRG’s conventional distributed generation business, consisting of reliability, combined heat and power, thermal and district heating and cooling and large-scale distributed generation.
NRG Business is capital-intensive and commodity-driven with numerous industry participants that compete on the basis of the location of their plants, fuel mix, plant efficiency and the reliability of the services offered. NRG Business includes one of the largest and most diversified power generation portfolios in the U.S., with approximately 47,636 MW of fossil fuel and nuclear generation capacity at 93 plants as of December 31, 2014. 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 during periods of high demand, which typically drive higher energy prices.
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 identities of the companies NRG Business competes with depending on the market. Competitors include regulated utilities, municipalities, cooperatives and other independent power producers, and power marketers or trading companies, including those owned by financial institutions. Many of NRG Business' generation assets, however, 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 Business now has generation assets located in or near Houston, New York City, Chicago, Washington D.C., New Jersey, southwestern Connecticut, Pittsburgh, Cleveland, and the Los Angeles, San Diego, and San Francisco metropolitan areas. These facilities, many of which are aging, 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. NRG Business believes that its extensive generation portfolio provides many asset optimization opportunities. To that end, NRG Business currently has approximately 5,626 MWs targeted for Repowering and conversion initiatives, with 905 MWs already under development or construction.
In addition, NRG Business continuously evaluates opportunities for development of new generation, on both a merchant and contracted basis. As such, the majority of NRG Business' current developments are in response to Requests For Proposals, or RFPs, for new generation and/or generating capacity backed by contracts with credit-worthy counterparties.  Many RFPs are solicited by regulated utilities or electric system operators, often to comply with reliability mandates measured by the reserve margin, which is the market's available electric power capacity over and above the electric power capacity needed to meet peak demand levels.  NRG Business competes against other power plant developers.  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 many factors including price, location of existing generation, prior experience developing generation resources similar to that specified in the RFP, and creditworthiness. NRG Renew, which is described below, competes in a similar manner on renewable projects.
NRG Business’s B2B solutions focus on providing distributed products and services (energy solutions) as businesses seek greater reliability, cleaner power or other benefits that they cannot obtain from the grid. These solutions include system power, distributed generation, solar and wind products, carbon management and specialty services, backup generation, storage and distributed solar, demand response and energy efficiency. In providing on-site energy solutions, NRG Business often benefits from its ability to supply energy products from its wholesale generation portfolio to commercial and industrial retail customers.
NRG Business also provides energy services including operations, maintenance, technical, development and asset management services to its own facilities and to external customers. Such energy services provide NRG Business with the competitive advantage to capture the crossover value between wholesale markets and distributed resources.

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NRG Home
NRG Home is a consumer facing business that includes the Company’s mass market retail business, the Company's residential solar business and a smaller home warranty and service business, combined into NRG Home in order to offer a diverse suite of personal energy solutions for use in and outside the home. NRG Home is focused on establishing deeply integrated multi-product, multi-service customer relationships that strengthen the consumer energy experience and allow individuals to generate and manage greater amounts of their own energy and to access their power at fixed sites and on the go.
NRG Home Retail — Under NRG Home, the NRG Home Retail business provides home energy and related services as well as personal power to consumers through various brands and channels across the U.S. In 2014, NRG Home Retail delivered approximately 41 TWhs and had approximately 2.8 million Recurring customers, including 540,000 customers from the acquisition of Dominion Resources, Inc. (as described in Item 15 — Note 3, Business Acquisitions and Dispositions) plus approximately 299,000 Discrete customers of products and services. NRG Home Retail's business results make it the largest energy retailer in Texas and one of the largest retail energy providers in the U.S., with the majority of its sales in the competitive retail energy markets of Connecticut, Delaware, Illinois, Maryland, Massachusetts, New Jersey, New York, Pennsylvania, Ohio and Texas, as well as the District of Columbia.
Retail customers make purchase decisions based on a variety of factors, including price, customer service, brand, product choices, bundles or value-added features. Customers purchase products through a variety of sales channels including direct sales, call centers, websites, brokers and brick-and-mortar stores. Through its broad range of service offerings and value propositions, the NRG Home Retail business is able to attract, retain, and increase the value of its customer relationships. NRG Home's retailers are recognized for exemplary customer service, innovative smart energy and technology product offerings and environmentally friendly solutions. In 2014, NRG Home acquired Goal Zero, a leading provider of portable solar power and battery pack products and accessories, through which NRG Home Retail strengthened its cross-selling opportunities between mass market system power, residential solar and personal power via partnerships, sales channels and customer bases.
In an industry that is subject to commodity price volatility, NRG expects that an expanded core generation fleet will enable NRG Home to replicate in multiple markets, principally in the Northeast, the successful integrated wholesale-retail business model that NRG Home currently operates in the Gulf Coast region.
NRG Home Solar NRG Home Solar offers a full complement of customer acquisition, installation and contract management services for residential solar customers. Through this full service approach, NRG Home Solar allows customers to switch to solar energy in a simple and cost-efficient manner. In 2014, the Company acquired one of the nation's leading residential solar companies, Roof Diagnostics Solar, now doing business as NRG Home Solar, to support and expand the Company's efforts to empower its customers to control their own energy choices through clean self-generation. Also in 2014, the Company acquired Pure Energies, a residential solar industry company focused on web and telephonic based customer acquisition. Pure Energies enables a simplified customer adoption process and provides NRG Home Solar national sales capabilities. In addition to leveraging the NRG Home Retail business, the combination of RDS and Pure Energies provides NRG Home Solar the platform to meet the growing demand for high quality residential solar services delivered by a market leader in delivering retail electricity services in the home.
NRG Home Solar competes against traditional power generation and retail services, including products and services provided by NRG Business and NRG Home Retail in that it offers, a full or partial alternative, to the provision of energy in and on the home. NRG Home Solar also competes with other solar companies in the downstream value chain of solar energy, including companies that subcontract the installation of these solar energy systems as well as installation, construction and roofing businesses that may offer competitive pricing. NRG Home Solar believes that its long-term track record, network of retail customers, customer acquisition capabilities and strong installation and servicing platforms make it the most competitively advantaged residential solar company in the U.S. Additionally, NRG Home Solar’s potential together with NRG Home Retail to offer customers seamless home solar/grid backup solutions, plus other cross-selling opportunities with other NRG Home products, will provide NRG Home a significant competitive advantage over time.


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NRG Renew
NRG Renew focuses on the Company’s existing renewables business and developing renewable products and services that are customizable generally for larger end use energy consumers, such as micro grid solutions. NRG Renew is one of the largest solar power developers and owner-operators in the U.S., having demonstrated the ability to develop, construct and finance a full range of solar energy solutions for utilities, schools, municipalities and commercial market segments. In 2014, NRG Renew became one of the largest domestic wind-operators when the Company acquired the wind assets from EME. As the traditional grid is becoming more unreliable for service-oriented merchants, and carbon pricing becomes an ever growing consideration, NRG Renew believes that its capabilities will allow it to become the sustainability and clean energy partner of choice for businesses ranging in size from local proprietors to Fortune 500 multinational corporations. It is a business that is positioned to capture emerging opportunities as the movement to sustainable energy resources continues to drive growth in this segment of the energy industry. NRG Renew, formerly known as NRG Solar, initially developed its utility scale operating portfolio by capitalizing on the first-mover advantage in response to state mandated renewable portfolio standards. As the increased demand for sustainable energy shifts to commercial and industrial market segments, health and educational institutions, governmental agencies and municipalities, NRG Renew will respond with customized, renewable led solutions supported by the breadth and depth of the Company’s power generation and financing capabilities.
NRG Renew targets strategic partnerships with local, regional, national and multi-national companies and institutions to provide onsite and offsite renewable generation for their partners, highlighted by a partnership to provide 100% clean energy for all energy use at Unilever United States, Inc. and a partnership with Starwood Hotels & Resorts for the installation of solar array at multiple Starwood properties to aid Starwood in achieving its target of 30% energy reduction by 2020. As of December 31, 2014, NRG Renew had approximately 47 MWs of Distributed Solar projects, all of which are supported by long-term PPAs, in operation or under construction, including five National Football League venues as well as other commercial or institutional sites, including a 6 MW project located on the MGM Mandalay Bay complex in Las Vegas, Nevada.
Similar to NRG Business, NRG Renew also competes for new generation opportunities through RFPs. The number and type of competitors vary based on location, generation type, project size and counterparty.  NRG Renew competes with traditional utilities as well as companies that provide products and services in the downstream solar and wind energy value chains. NRG Renew also competes with products and services provided by NRG Business as well as traditional utility and power plant companies.
NRG Yield
NRG Yield, Inc. is a publicly traded dividend growth-oriented company formed to serve as the primary vehicle through which NRG, supported by NRG Renew and NRG Business, owns, operates and acquires diversified contracted renewable and conventional generation and thermal infrastructure assets. As of December 31, 2014, NRG owns 55.3% of the outstanding common stock of NRG Yield, Inc. NRG Yield, Inc.’s contracted generation portfolio collectively represents 2,861 net MW as of December 31, 2014. Each of the assets sells substantially all of its output pursuant to long-term, fixed price offtake agreements with creditworthy counterparties. NRG Yield, Inc. also owns thermal infrastructure assets with an aggregate steam and chilled water capacity of 1,346 net MWt and electric generation capacity of 123 net MW. These thermal infrastructure assets provide steam, hot water and/or chilled water, and in some instances electricity, to commercial businesses, universities, hospitals and governmental units in multiple locations, principally through long-term contracts or pursuant to rates regulated by state utility commissions.
NRG Yield, Inc. provides the Company with a more competitive cost of capital consistent with the lower risk profile of long-term contracted or regulated assets. As such, NRG believes that it will directly benefit from NRG Yield, Inc.’s growth through its controlling interest in NRG Yield, Inc. and by providing NRG Yield, Inc. a platform of growth through the completion of future sales of assets pursuant to the Right of First Offer Agreement. The proceeds of such sales are expected to provide the Company with capital to expand its Capital Allocation Program.  As of December 31, 2014, NRG Yield, Inc.’s stock price had increased 114.3% from its initial public offering price of $22 per share on July 17, 2013.
On February 24, 2015, NRG Yield, Inc.’s board of directors approved amendments to the NRG Yield, Inc. certificate of incorporation that would, among other things, create two new classes of capital stock, Class C common stock and Class D common stock. The amendments will be voted on at the NRG Yield, Inc. Annual Meeting of Stockholders to be held on May 5, 2015. If such amendments are approved, NRG Yield, Inc. intends to request that the board of directors consider a distribution of shares of the Class C common stock as a dividend to the holders of the Class A common stock and a distribution of shares of the Class D common stock as a dividend to NRG, the holder of the Class B common stock. The Class C common stock and Class D common stock will have the same rights and privileges and rank equally, share ratably and be identical in all respects to the shares of Class A common stock and Class B common stock, respectively, as to all matters, except that each share of Class C common stock and Class D common stock will be entitled to 1/100th of a vote on all stockholder matters.

11

                                                                                     


In addition, subject to the approval of the proposed amendments described above, NRG has agreed to amend the Right of First Offer Agreement to make additional assets available to NRG Yield, Inc. should NRG choose to sell them, including (i) two natural gas facilities totaling 895 MW of net capacity that are expected to reach COD in 2017 and 2020, (ii) an equity interest in a wind portfolio that includes wind facilities totaling approximately 934 MW of net capacity, and (iii) up to $250 million of equity interests in one or more residential or distributed solar generation portfolios developed by affiliates of NRG.
NRG Carbon 360
NRG Carbon 360 consists of the Company’s carbon capture business that plans to develop carbon capture facilities for NRG that may prolong the life of NRG’s coal fleet and convert NRG's carbon emissions from a liability to a productive asset. To that end, in July 2014, the Company formed a joint venture with JX Nippon Oil & Gas Exploration Corporation (JX Nippon), to build and operate the Petra Nova Carbon Capture Project, or the Petra Nova Project. The Petra Nova Project is expected to be a commercial-scale carbon capture system that captures 90% of the CO2 in the processed flue gas from an existing unit at the WA Parish power plant in Fort Bend County, southwest of Houston. Commercial operation is expected in late 2016. The Petra Nova Project is being financed by: (i) up to $167 million from a U.S. DOE CCPI grant, (ii) $250 million in loans provided by the Japan Bank for International Cooperation and Mizuho Bank, Ltd., and (iii) approximately $300 million in equity contributions from each of the Company and JX Nippon. The joint venture also owns a 50% equity interest in Texas Coastal Ventures, LLC, which holds working interests in the West Ranch oil field in Jackson County, Texas.  NRG Carbon 360 continues to assess oilfield opportunities both along the Gulf Coast and nationally as it looks to further monetize the carbon output of NRG's fleet. In connection with the formation of the joint venture with JX Nippon, the Company no longer has a controlling interest in the project and the joint venture is not consolidated in the Company’s financial statements. NRG Carbon 360 is reflected in the Company's NRG Business segment.
NRG eVgo
NRG eVgo, the results of which are reflected in the Company's Corporate segment, is the Company’s electric vehicle charging services business which serves the interest of NRG not only by stimulating electricity demand but also by creating a distinct, and fast growing, set of end use energy consumers secured through a nontraditional sales channel. NRG eVgo continues to build out and operate electric vehicle, or EV, charging infrastructure in the U.S. NRG eVgo provides comprehensive EV charging - at public, home, multi-family and workplace locations - in major metropolitan areas throughout the country. As of December 31, 2014, NRG eVgo had 238 operational public fast chargers. NRG eVgo offers consumers a choice of subscription-based plans, all at competitive monthly fees, as well as walk-up charging. In the third quarter of 2014, NRG eVgo initiated support of Nissan’s expanded "No Charge to Charge" program, which provides Nissan customers with up to two years of no-cost public charging on participating networks with the purchase or lease of a new Nissan LEAF, utilizing the EZ-Charge (SM) interoperability card. NRG eVgo also signed an agreement with BMW to offer i3 owners in California a one-year embedded subscription through 2015. These two agreements and NRG eVgo trial programs at more than 200 participating auto dealers have resulted in significant increases in customer count.
In addition, as part of a legal settlement, NRG eVgo has an agreement with the California Public Utilities Commission to build at least 200 public fast charging Freedom Station sites and associated work to prepare 10,000 commercial and multi-family parking spaces for electric vehicle charging in California by the end of 2016.

12

                                                                                     

NRG Operations
The NRG businesses described above are all supported through the NRG operational infrastructure, which begins with the Company’s asset fleet and the associated commercial and retail operations. The images below illustrate NRG's U.S. power generation and net capacity capabilities as of December 31, 2014, as well as customer, load and regional information surrounding the operation of NRG’s retail businesses:
    

13

                                                                                     

The following table summarizes NRG's global generation portfolio as of December 31, 2014:
 
 
Global Generation Portfolio(a)
 
 
(In MW)
 
 
NRG Business
 
 
 
 
 
 
 
 
 
 
 
 
Generation Type
 
Gulf Coast
 
East
 
West
 
NRG Home Solar
 
NRG Renew
 
NRG Yield (b)
 
Total Domestic
 
Other (Inter-national)
 
Total Global
Natural gas
 
8,547

 
7,744

 
7,617

 

 

 
1,393

 
25,301

 
144

 
25,445

Coal
 
5,689

 
11,045

 

 

 

 

 
16,734

 
605

 
17,339

Oil
 

 
5,818

 

 

 

 
190

 
6,008

 

 
6,008

Nuclear
 
1,176

 

 

 

 

 

 
1,176

 

 
1,176

Wind
 

 

 

 

 
1,964

 
1,048

 
3,012

 

 
3,012

Utility Scale Solar
 

 

 

 

 
807

 
343

 
1,150

 

 
1,150

Distributed Solar
 

 

 

 
50

 
37

 
10

 
97

 

 
97

Total generation capacity
 
15,412

 
24,607

 
7,617

 
50

 
2,808

 
2,984

 
53,478

 
749

 
54,227

Capacity attributable to noncontrolling interest
 

 

 

 

 
(630
)
 
(1,334
)
 
(1,964
)
 

 
(1,964
)
Total net generation capacity
 
15,412

 
24,607

 
7,617

 
50

 
2,178

 
1,650

 
51,514

 
749

 
52,263

(a) Includes 95 active fossil fuel and nuclear plants, 14 Utility Scale Solar facilities, 35 wind farms and multiple Distributed Solar facilities. All Utility Scale Solar and Distributed Solar facilities are described in megawatts on an alternating current basis. MW figures provided represent nominal summer net megawatt capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.
(b) The NRG Yield operating segment consists of two dual-fuel (natural gas and oil) simple-cycle generation facilities. In addition, the Company's thermal assets, which are part of the NRG Yield operating segment, provide steam and chilled water capacity of approximately 1,464 MWt through the district energy business, 118 MWt of which is available under right-to-use provisions contained in agreements between two of NRG's thermal facilities and certain of their customers.
NRG's portfolio diversification and commercial operations hedging strategy provides the Company with reliable future cash flows. NRG has hedged a portion of its coal and nuclear capacity with decreasing hedge levels through 2019. As a result of the GenOn acquisition, the majority of the Company's generation is in markets with forward capacity markets that extend three years into the future. These capacity revenues not only enhance the reliability of future cash flows but are not correlated to natural gas prices. NRG also has cooperative load contract obligations in the Gulf Coast region expiring at various dates through 2025, which largely hedges the Company's generation in this region. In addition, as of December 31, 2014, the Company had purchased fuel forward under fixed price contracts, with contractually-specified price escalators, for approximately 50% of its expected coal requirement from 2015 to 2019, excluding inventory. The Company enters into additional hedges when it deems market conditions to be 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 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 new renewable and conventional power generation facilities, NRG typically secures long-term 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 from 10 years to as much as 25 years.

14

                                                                                     

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 PPAs, fuel supply contracts, capacity auctions, natural gas derivative instruments and other financial instruments. 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 that may include power and natural gas forward sales contracts to manage the commodity price risk primarily associated with the Company's coal and nuclear generation assets. The objective of these hedging strategies is to stabilize the cash flow generated by NRG's portfolio of assets.
NRG also trades electric power, natural gas, oil, weather and related commodity and financial products, including forwards, futures, options and swaps, primarily through its ownership of Boston Energy Trading and Marketing, or BETM, which was acquired in the acquisition of EME. BETM seeks to generate profits from volatility in the price of electricity, capacity, fuels and transmission congestion by buying and selling contracts in wholesale markets under guidelines approved by the Company's risk management committee.
Coal and Nuclear Operations
The following table summarizes NRG's U.S. coal and nuclear capacity and the corresponding revenues and average natural gas prices and positions resulting from coal and nuclear hedge agreements extending beyond December 31, 2014, and through 2018 for the Company's Gulf Coast region:
Gulf Coast
 
2015
 
2016
 
2017
 
2018
 
Annual
Average for
2015-2018
 
 
(Dollars in millions unless otherwise stated)
Net Coal and Nuclear Capacity (MW) (a)
 
6,290

 
6,290

 
6,290

 
6,290

 
6,290

Forecasted Coal and Nuclear Capacity (MW) (b)
 
4,739

 
5,097

 
5,261

 
5,225

 
5,081

Total Coal and Nuclear Sales (MW) (c)
 
5,629

 
2,909

 
1,251

 
1,000

 
2,697

Percentage Coal and Nuclear Capacity Sold Forward (d)
 
119
%
 
57
%
 
24
%
 
19
%
 
55
%
Total Forward Hedged Revenues (e)
 
$
2,224

 
$
1,128

 
$
502

 
$
435

 
 
Weighted Average Hedged Price ($ per MWh) (e)
 
$
45.11

 
$
44.15

 
$
45.82

 
$
49.67

 
 
Average Equivalent Natural Gas Price ($ per MMBtu) (e)
 
$
3.99

 
$
4.28

 
$
4.42

 
$
4.75

 
 
Gas Price Sensitivity Up $0.50/MMBtu on Coal and Nuclear Units
 
$
(12
)
 
$
118

 
$
188

 
$
197

 
 
Gas Price Sensitivity Down $0.50/MMBtu on Coal and Nuclear Units
 
$
40

 
$
(109
)
 
$
(183
)
 
$
(187
)
 
 
Heat Rate Sensitivity Up 1 MMBtu/MWh on Coal and Nuclear Units
 
$
12

 
$
104

 
$
144

 
$
155

 
 
Heat Rate Sensitivity Down 1 MMBtu/MWh on Coal and Nuclear Units
 
$
8

 
$
(86
)
 
$
(128
)
 
$
(138
)
 
 
(a)
Net coal and nuclear capacity represents nominal summer net MW capacity of power generated as adjusted for the Company's ownership position excluding capacity from inactive/mothballed units, see Item 2 - Properties for units scheduled to be deactivated.
(b)
Forecasted generation dispatch output (MWh) based on forward price curves as of December 31, 2014, 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.
(c)
Includes amounts under power sales contracts and natural gas hedges. The forward natural gas quantities are reflected in equivalent MWh based on forward market implied heat rate as of December 31, 2014, and then combined with power sales to arrive at equivalent MWh hedged which is then divided by number of hours in a given year to arrive at MW hedged. The coal and nuclear 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 5, Accounting for Derivative Instruments and Hedging Activities, to the Consolidated Financial Statements. Includes inter-segment sales from the Company's wholesale power generation business to the retail business.
(d)
Percentage hedged is based on total coal and nuclear sales as described in (c) above divided by the forecasted coal and nuclear capacity.
(e)
Represents U.S. coal and nuclear sales, including energy revenue and demand charges.

15

                                                                                     

The following table summarizes NRG's U.S. coal capacity and the corresponding revenues and average natural gas prices and positions resulting from coal hedge agreements extending beyond December 31, 2014, and through 2018 for the East region:
East
 
2015
 
2016
 
2017
 
2018
 
Annual
Average for
2015-2018
 
 
(Dollars in millions unless otherwise stated)
Net Coal Capacity (MW) (a)
 
10,401

 
8,732

 
7,280

 
7,132

 
8,386

Forecasted Coal Capacity (MW) (b)
 
4,888

 
3,482

 
2,971

 
2,631

 
3,493

Total Coal Sales (MW) (c)
 
5,503

 
1,575

 
514

 

 
1,898

Percentage Coal Capacity Sold Forward (d)
 
113
%
 
45
%
 
17
%
 
%
 
44
%
Total Forward Hedged Revenues (e)
 
$
2,292

 
$
735

 
$
198

 
$

 
 
Weighted Average Hedged Price ($ per MWh) (e)
 
$
47.56

 
$
53.12

 
$
43.89

 
$

 
 
Average Equivalent Natural Gas Price ($ per MMBtu) (e)
 
$
3.48

 
$
4.23

 
$
4.33

 
$

 
 
Gas Price Sensitivity Up $0.50/MMBtu on Coal Units
 
$
82

 
$
160

 
$
186

 
$
178

 
 
Gas Price Sensitivity Down $0.50/MMBtu on Coal Units
 
$
14

 
$
(97
)
 
$
(136
)
 
$
(137
)
 
 
Heat Rate Sensitivity Up 1 MMBtu/MWh on Coal Units
 
$
36

 
$
101

 
$
145

 
$
133

 
 
Heat Rate Sensitivity Down 1 MMBtu/MWh on Coal Units
 
$
7

 
$
(65
)
 
$
(103
)
 
$
(98
)
 
 
(a)
Net coal capacity represents nominal summer net MW capacity of power generated as adjusted for the Company's ownership position excluding capacity from inactive/mothballed units, see Item 2 - Properties for units scheduled to be deactivated.
(b)
Forecasted generation dispatch output (MWh) based on forward price curves as of December 31, 2014, 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.
(c)
Includes amounts under power sales contracts and natural gas hedges. The forward natural gas quantities are reflected in equivalent MWh based on forward market implied heat rate as of December 31, 2014, and then combined with power sales to arrive at equivalent MWh hedged which is then divided by number of hours in a given year to arrive at MW hedged. The coal 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 5, Accounting for Derivative Instruments and Hedging Activities, to the Consolidated Financial Statements. Includes inter-segment sales from the Company's wholesale power generation business to the retail business.
(d)
Percentage hedged is based on total coal sales as described in (c) above divided by the forecasted coal capacity.
(e)
Represents U.S. coal sales, including energy revenue and demand charges, excluding revenues derived from capacity auctions.
Retail Operations
In 2014, NRG's retail businesses within NRG Home and NRG Business sold electricity to residential, commercial and industrial consumers at either fixed, indexed or variable prices. Residential and smaller commercial consumers typically contract for terms ranging from one month to two years while industrial contracts are often between one year and five years in length. In 2014, NRG's retail businesses sold approximately 63 TWhs of electricity. In any given year, the quantity of TWh sold can be affected by weather, economic conditions and competition. The wholesale supply is typically purchased as the load is contracted from a combination of NRG's wholesale portfolio and other third parties. The ability to choose supply from the market or the Company's portfolio allows for an optimal combination to support and stabilize retail margins.

16

                                                                                     

Capacity and Other Contracted Revenue Sources
NRG's revenues and cash flows benefit from capacity/demand payments and other contracted revenue sources, originating from market clearing capacity prices, Resource Adequacy contracts, tolling arrangements, PPAs and other long-term contractual arrangements:
NRG Business — The Company's largest sources of capacity revenues are capacity auctions in PJM, ISO-NE, and NYISO. In California, there is a regulatory mandated resource adequacy requirement that is satisfied through bilateral contracts. The Company's newer generation in California is contracted under long-term tolling agreements. Certain other sites in California have short-term tolling agreements or resource adequacy contracts. In addition, NRG earns demand payments from its long-term full-requirements load contracts with ten Louisiana distribution cooperatives. Of the ten contracts, nine expire in 2025 and account for 75% of the cooperative customer contract load. The remaining counterparty, with a 550 MW load service contract, accounting for 25% of the cooperative total, elected not to extend its contract when it expired 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 the costs associated with new or changed environmental laws or regulations. MISO has a Resource Adequacy Construct and an annual auction, known as the Planning Resource Auction, or PRA. The Gulf Coast assets situated in the MISO market may participate in this auction.  In certain circumstances, capacity from the Gulf Coast region may be sold into the PJM market. In Texas, capacity and contracted revenues are through bilateral contracts with load serving entities.
NRG Renew — Output from renewable energy assets are generally sold through long-term PPAs.
NRG Yield — NRG Yield's share of renewable and conventional energy plants is generally sold through long-term PPAs and tolling agreements. Output from NRG Yield's share of 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. Two of the PJM generation assets participate in the PJM capacity markets.
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, delays arising from extreme weather conditions 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 and fuel products used.
Coal — The Company believes it is adequately hedged, using forward coal supply agreements for its domestic coal consumption for 2015. NRG actively manages its coal requirements based on forecasted generation, market volatility and its inventory on site. As of December 31, 2014, NRG had purchased forward contracts to provide fuel for approximately 50% of the Company's expected requirements from 2015 through 2019, excluding inventory. NRG purchased approximately 46 million tons of coal in 2014, of which 80% was Powder River Basin coal and lignite, and 20% was waste and Appalachian coal. For fuel transport, NRG has entered into various rail, barge, truck transportation and rail car lease agreements with varying tenures that provide for substantially all of the Company's transportation requirement of Powder River Basin coal for the next two years and for most of the Company's transportation requirements of Appalachian coal for the next year.
The following table shows the percentage of the Company's coal requirements from 2015 through 2019 that have been purchased forward as of December 31, 2014:
 
Percentage of
Company's
Requirement (a)(b)
2015
100
%
2016
75
%
2017
34
%
2018
19
%
2019
21
%
(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.

17

                                                                                     

Natural Gas — NRG operates a fleet of mid-merit and peaking natural gas plants across all its U.S. wholesale regions. Fuel needs are managed on a spot basis, especially for peaking assets, 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 deliver natural gas when needed.
Nuclear Fuel — STP's owners satisfy their 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 STPNOC, which is the 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's requirements for uranium concentrates with only approximately 25% of STP's requirements outstanding for the duration of the operating license. Similarly, NRG is party to long-term contracts to procure STP's requirements for conversion and 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 total power prices and market dynamics like the price of natural gas, transmission constraints, competitor actions, and changes in market heat rates.
Operational Statistics
The following are industry statistics for the Company's fossil and nuclear plants, as defined by the 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 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.

18

                                                                                     

The tables below present these performance metrics for the Company's U.S. power generation portfolio, including leased facilities and those accounted for through equity method investments, for the years ended December 31, 2014, and 2013:
 
Year Ended December 31, 2014
 
 
 
 
 
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)
NRG Business
 
 
 
 
 
 
 
 
 
Gulf Coast
15,412

 
59,872

 
86.6
%
 
9,694

 
44.6
%
East
24,607

 
51,292

 
81.8

 
10,392

 
25.6

West
7,617

 
5,409

 
91.1

 
8,967

 
9.0

NRG Renew
2,808

 
6,992

 
 
 
 
 
 
NRG Yield (a)
2,984

 
5,011

 
95.1

 
8,702

 
13.5

 
Year Ended December 31, 2013
 
 
 
 
 
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)
NRG Business
 
 
 
 
 
 
 
 
 
Gulf Coast
16,599

 
57,193

 
82.9
%
 
9,900

 
41.3
%
East
20,061

 
34,081

 
80.8

 
10,100

 
17.6

West
6,229

 
2,876

 
89.5

 
11,800

 
4.8

NRG Renew
1,180

 
2,074

 
 
 
 
 
 
NRG Yield (a)
2,037

 
3,443

 
91.4

 
8,900

 
8.5

(a)
NRG Yield excludes thermal generation.
The generation performance by region for the three years ended December 31, 2014, 2013, and 2012, is shown below:
 
Net Generation
 
2014
 
2013
 
2012 (a)
 
(In thousands of MWh)
NRG Business
 
 
 
 
 
Gulf Coast
 
 
 
 
 
Coal
36,794

 
37,635

 
31,144

Gas
13,968

 
11,674

 
11,229

Nuclear (b)
9,110

 
7,884

 
7,269

Total Gulf Coast
59,872

 
57,193

 
49,642

East
 
 
 
 
 
Coal
43,604

 
25,853

 
3,228

Oil
767

 
364

 
233

Gas
6,921

 
7,864

 
1,744

Total East
51,292

 
34,081

 
5,205

West
 
 
 
 
 
Gas
5,409

 
2,876

 
2,011

Total West
5,409

 
2,876

 
2,011

NRG Renew
 
 
 
 
 
Solar
1,901

 
1,153

 
569

Wind
5,091

 
921

 
806

Total NRG Renew
6,992

 
2,074

 
1,375

NRG Yield
 
 
 
 
 
Solar
550

 
520

 
105

Wind
1,002

 
334

 
317

Gas and Dual-Fuel
3,459

 
2,589

 
1,098

Total NRG Yield (c)
5,011

 
3,443

 
1,520

(a)
Includes GenOn generation for the period from December 15, 2012, through December 31, 2012.
(b)
MWh information reflects the Company's undivided interest in total MWh generated by STP.
(c)
Total NRG Yield excludes thermal generation.

19

                                                                                     

Segment Review
Effective in December 2014, the Company's segment structure and its allocation of corporate expenses were updated to reflect how management currently makes financial decisions and allocates resources. The Company has recast data from prior periods to reflect this change in reportable segments to conform to the current year presentation. The Company's businesses are segregated as follows: NRG Business; NRG Home, which includes NRG Home Retail and NRG Home Solar; NRG Renew, which includes solar and wind assets, excluding those in the NRG Yield; NRG Yield and corporate activities.  NRG Yield includes certain of the Company's contracted generation assets. On June 30, 2014, NRG Yield, Inc. acquired three projects from the Company: El Segundo Energy Center, formerly in the NRG Business segment, Kansas South and High Desert, both formerly in the NRG Renew segment. As the transaction was accounted for as a transfer of entities under common control, all historical periods have been recast to reflect this change.
Revenues
The following table contains a summary of NRG's operating revenues by segment for the years ended December 31, 2014, 2013, and 2012, 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, 2014
 
Energy
Revenues
 
Capacity
Revenues
 
Retail
Revenues
 
Mark-to-
Market
Activities
 
Contract Amor-tization
 
Other
Revenues(a)
 
Total
Operating
Revenues(b)
 
(In millions)
NRG Business
$
6,480

 
$
1,860

 
$
1,868

 
$
535

 
$
11

 
$
340

 
$
11,094

NRG Home Retail

 

 
5,505

 

 
1

 

 
5,506

NRG Home Solar

 

 
12

 

 

 

 
12

NRG Renew
477

 
2

 

 
6

 
(7
)
 
35

 
513

NRG Yield
173

 
247

 

 

 
(18
)
 
181

 
583

Corporate and Eliminations (b)
(1,708
)
 
(22
)
 
(9
)
 
(40
)
 

 
(61
)
 
(1,840
)
Total
$
5,422

 
$
2,087

 
$
7,376

 
$
501

 
$
(13
)
 
$
495

 
$
15,868

(a)
Primarily consists of revenues generated by the Thermal business, operation and maintenance revenues and unrealized trading activities.
(b)
Energy revenues include inter-segment sales primarily between NRG Business and NRG Home.
 
Year Ended December 31, 2013
 
Energy
Revenues
 
Capacity
Revenues
 
Retail
Revenues
 
Mark-to-
Market
Activities
 
Contract Amor-tization
 
Other
Revenues(c)
 
Total
Operating
Revenues(d)
 
(In millions)
NRG Business
$
5,335

 
$
1,720

 
$
1,909

 
$
(541
)
 
$
21

 
$
193

 
$
8,637

NRG Home Retail

 

 
4,392

 

 
(51
)
 

 
4,341

NRG Home Solar

 

 
4

 

 

 

 
4

NRG Renew
198

 

 

 
(1
)
 

 
25

 
222

NRG Yield
103

 
140

 

 

 
(1
)
 
137

 
379

Corporate and Eliminations (d)
(2,106
)
 
(60
)
 
(5
)
 
(36
)
 

 
(81
)
 
(2,288
)
Total
$
3,530

 
$
1,800

 
$
6,300

 
$
(578
)
 
$
(31
)
 
$
274

 
$
11,295

(c)
Primarily consists of revenues generated by the Thermal business, operation and maintenance revenues and unrealized trading activities.
(d)
Energy revenues include inter-segment sales primarily between NRG Business and NRG Home.
 
Year Ended December 31, 2012
 
Energy
Revenues
 
Capacity
Revenues
 
Retail
Revenues(f)
 
Mark-to-
Market
Activities
 
Contract Amor-tization
 
Other
Revenues(e)
 
Total
Operating
Revenues (f)
 
(In millions)
NRG Business
$
3,588

 
$
765

 
$
1,907

 
$
(413
)
 
$
20

 
$
109

 
$
5,976

NRG Home Retail

 

 
3,993

 
(5
)
 
(116
)
 

 
3,872

NRG Home Solar

 

 

 

 

 
3

 
3

NRG Renew
117

 

 

 

 

 
5

 
122

NRG Yield
33

 

 

 

 
(1
)
 
143

 
175

Corporate and Eliminations(g)
(1,624
)
 
(3
)
 

 
(32
)
 

 
(67
)
 
(1,726
)
Total
$
2,114

 
$
762

 
$
5,900

 
$
(450
)
 
$
(97
)
 
$
193

 
$
8,422

(e)
Primarily consists of revenues generated by the Thermal business, operation and maintenance revenues and unrealized trading activities.
(f)
Total operating revenues includes GenOn revenues of $73 million for the period from December 15, 2012, to December 31, 2012.
(g)
Energy revenues include inter-segment sales primarily between NRG Business and NRG Home.

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Market Framework
Organized Energy Markets in CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM
The majority of NRG's fleet operates in one of the organized energy markets, known as RTOs or ISOs. Each organized market administers day-ahead and real-time centralized bid-based energy and ancillary services markets pursuant to tariffs approved by FERC, or in the case of ERCOT, market rules approved by the PUCT. These tariffs and rules dictate how the energy markets operate, how market participants make bilateral sales with one another, and how entities with market-based rates are compensated. Established prices reflect the value of energy at the specific location and time it is delivered, which is known as the Locational Marginal Price, or LMP. Each market is subject to market mitigation measures designed to limit the exercise of locational market power. These market structures facilitate NRG's sale of power and capacity products at market-based rates.
Other than ERCOT, each of the ISO regions also operates a capacity or resource adequacy market that provides an opportunity for generating and demand response resources to earn revenues to offset their fixed costs that are not recovered in the energy and ancillary services markets. The ISOs are also responsible for transmission planning and operations.
Gulf Coast
NRG's Gulf Coast wholesale power generation business is principally located in the ERCOT and MISO markets. The ERCOT market is one of the nation's largest and historically fastest growing power markets. For 2014, hourly demand ranged from a low of approximately 24,540 MW to a high of approximately 66,400 MW. The all-time peak demand in ERCOT remains 68,305 MW, set on August 3, 2011 during the hottest summer on record. The ERCOT region contains installed generation capacity of approximately 89,200 MW (approximately 23,300 MW from coal, lignite and nuclear plants, 48,600 MW from gas, and 17,300 MW from wind, hydro, solar, biomass and behind-the-meter generation). The ERCOT market has limited interconnections to other markets in the U.S. In addition, NRG's retail business activities in Texas are subject to standards and regulations adopted by the PUCT and ERCOT, including the requirement for retailers to be certified by the PUCT in order to contract with end-users to sell electricity. In Texas, a majority of the load is in the ERCOT market region and is served by competitive retail suppliers, except certain areas that are served by municipal utilities and electric cooperatives that have not opted into competitive choice.
Recently, a number of market rule changes have been implemented to provide pricing more reflective of higher energy value when operating reserves are scarce or constrained. The primary stated goal of these market rule changes is to improve forward market pricing signals and provide incentives for resource investment. Among the changes already implemented are: energy offer floors for certain ancillary service deployments, an increase to the system-wide energy and ancillary service offer caps, currently at $7,000 per MWh but will increase to $9,000 in June 2015, an increase to the annual peaker net margin threshold to $262,500 from $175,000, an increase to the low system-wide energy offer cap to $2,000 (up from $500), higher energy pricing for ISO unit commitments for capacity, and energy price adders to offset the price suppressing impacts of out-of-market commitments for reliability.
At the direction of the PUCT, ERCOT implemented an operating reserve demand curve, known as ORDC, on June 1, 2014. ORDC simulates real-time co-optimization of energy and reserves and uses price adders during scarcity conditions to reflect price formation outcomes expected under real-time co-optimization. Under ORDC, real time energy prices could rise to $9,000 per MWh during extreme scarcity events (due to value of lost load assumptions in the price curve), despite the current system wide offer cap of $7,000 per MWh.
On December 19, 2013, Entergy joined MISO and, as a result, NRG's Gulf Coast region generation assets operating in the Entergy region, are now principally located within the MISO, participating in the MISO day-ahead and real-time energy and ancillary services markets. Additionally, MISO employs a one-year forward resource adequacy construct, in which capacity resources can compete for fixed cost recovery in the capacity auction. NRG continues to provide full requirement services to load-serving entities, including cooperatives and municipalities in the MISO region.

21

                                                                                     

East
NRG's generation assets located in the East region of the U.S. are within the control areas of the NYISO, ISO-NE, and PJM. Each of the market regions in the East region provides for robust competition in the day-ahead and real-time energy and ancillary services markets. Additionally, each allows capacity resources to compete for fixed cost recovery in a capacity auction.
The East region achieves a significant portion of its revenues from capacity markets in ISO-NE, NYISO and PJM. PJM and ISO-NE employ a three-year forward capacity auction construct, while NYISO employs a month-ahead capacity auction construct. Capacity market prices are sensitive to design parameters, as well as additions of new capacity. In 2014, ISO-NE began transitioning its capacity market structure into a hybrid energy-capacity market, whereby suppliers would be subject to extremely high capacity penalties if they failed to deliver during reserve shortage conditions. As part of the reforms, capacity suppliers are allowed to include a wider array of costs in their capacity market bids, including a risk premium to account for the enhanced penalty risk. The “Performance Incentives” program, as it is known, takes effect in the 2018/2019 delivery year.
In December 2014, PJM proposed a similar set of rules, modeled on the New England rules. Like New England’s Performance Incentive program, PJM’s “Capacity Performance” proposal also imposes stiff new penalties on suppliers that fail to deliver energy during defined emergency conditions. FERC is expected to rule on PJM’s Capacity Performance proposal in early 2015.
West
The Company 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 primarily through nodal prices. 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 LSEs. The CPUC also determines specific capacity requirements for specified local areas utilizing inputs from the CAISO. Both the CAISO and CPUC rules require LSEs to contract with sufficient generation resources in order to maintain minimum levels of generation within defined local delivery areas. Additionally, the CAISO has independent authority to contract with needed resources under certain circumstances.
The increase in renewable resources in California is expected to drive a growing need for generation resources with increased operating flexibility, in addition to the established need for dispatchable generation within transmission-constrained areas of the transmission system, such as the San Diego, Greater San Francisco Bay Area, Big Creek/Ventura, 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 initiatives.  The Company is pursuing repowering projects at several of its Southern California sites pursuant to long-term contracts.
Renew
The Company operates a fast-growing fleet of utility scale and distributed renewable generating assets across the U.S. Many states have implemented their own renewable portfolio standard requiring LSEs to provide a given percentage of their production from renewable resources, such as 33% of generation by 2020 in California. As a result, a number of LSEs have entered into long-term PPAs with the Company's utility scale renewable generating facilities. The Company currently has PPAs for over 500 MW of solar generation assets located in California and Arizona and over 1,500 MW of wind generation assets. In California and Arizona, investor-owned utilities are nearing their procurement requirement, resulting in a trend towards smaller sized utility scale projects and a shift of contracting to municipalities and other public power entities. On December 19, 2014, the Tax Increase Prevention Act of 2014, or the TIPA, was enacted, which extended the PTC through the end of 2014.  The effective date of the TIPA is January 1, 2014, and as such, certain projects that commenced construction or took other qualifying actions during 2014 are now eligible to claim the PTC. This extension may create additional competition for NRG Renew and NRG Business with the development of additional generation assets, but also may create additional acquisition opportunities for NRG Yield to the extent such generation assets are contracted.

22

                                                                                     

Home
NRG Home, which includes the NRG Home Retail business and the NRG Home Solar business, provides customers with a full suite of competitive energy supply options, which include everything from traditional retail supply arrangements, rooftop solar, home energy products and services, portable power and battery products.
NRG Home's retail business sells energy and related services as well as portable power and battery solutions to customers across the country. In most of the states that have introduced retail competition, NRG Home competitively offers retail power, natural gas, portable power or other value-enhancing services to end use customers. Each retail choice state establishes its own retail competition laws and regulations, and the specific operational, licensing, and compliance requirements vary on a state-by-state basis. In the East markets, incumbent utilities currently provide default service and as a result typically serve a majority of residential customers. Regulated terms and conditions of default service, as well as any movement to replace default service with competitive services, as is done in ERCOT, can affect customer participation in retail competition. The attractiveness of NRG Home's offerings in each state may be impacted by the rules, regulations, market structure and communication requirements from public utility commissions across the country.
The NRG Home Solar business operates across an increasing number of states where solar solutions are attractive and price competitive to consumers. As success in the NRG Home Solar segment of the market builds, the states' public utility commissions are expected to reevaluate policies created to encourage the growth of this market segment. For example, many state public service commissions are evaluating changes to their retail rules, including net metering rules, imposition of minimum bills or an increased fixed component to bills, among other potential changes.
Regulatory Matters
As owners 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 CFTC, FERC, NRC, and the 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 and RTO 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 the North American Electric Reliability Corporation 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 FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by the PUCT, as well as to regulation by the NRC with respect to the Company's ownership interest in STP.
Federal Regulation
CFTC
The CFTC, among other things, has regulatory oversight authority over the trading of swaps, futures and many commodities under the Commodity Exchange Act, or CEA. The Dodd-Frank Act amended the CEA and increased the CFTC's regulatory authority on matters related to futures and over-the-counter derivatives trading like interest rate swaps.
The Company expects that, in 2015 and thereafter, the CFTC will further clarify the scope of the Dodd-Frank Act and publish additional rules concerning margin requirements and other issues that could affect the Company's over-the-counter derivatives trading. Because there are many details that remain to be addressed through CFTC rulemaking proceedings, at this time NRG cannot fully measure the impact of the Dodd-Frank Act on the Company, its operations or collateral requirements.
FERC
FERC, among other things, regulates the transmission and the wholesale sale by public utilities of electricity in interstate commerce under the authority of the FPA. Under existing regulations, FERC determines whether an entity owning a generation facility is an EWG as defined in the PUHCA. FERC also determines whether a generation facility meets the ownership and technical criteria of a QF under PURPA. The transmission of electric energy occurring wholly within ERCOT is not subject to FERC's rate jurisdiction under Sections 203 or 205 of the FPA. Each of NRG's non-ERCOT U.S. generating facilities either qualifies as a QF, or the subsidiary owning the facility qualifies as an EWG.
Public utilities are required to obtain FERC's acceptance, pursuant to Section 205 of the FPA, of their rate schedules for the wholesale sale of electricity. Generally 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.

23

                                                                                     

Court Rejects FERC’s Jurisdiction Over Demand Response — On May 23, 2014, the U.S. Court of Appeals for the District of Columbia Circuit vacated FERC’s rules (known as Order No. 745) that allow demand response resources to participate in the FERC-jurisdictional energy markets. The Court of Appeals held that the Federal Power Act does not authorize FERC to exercise jurisdiction over demand response and that instead demand response is part of the retail market over which the states have jurisdiction. The specific order being challenged related to energy market compensation, but this ruling also calls into question whether demand response will be permitted to participate in the capacity markets in the future. The U.S. Court of Appeals for the District of Columbia Circuit issued a stay of its decision in order to allow the U.S. Supreme Court to consider the case. The U.S. Solicitor General, on behalf of FERC, filed a petition for a writ of certiorari on January 15, 2015.  On the same date, EnerNOC, Inc. and other private entities filed their own petition for a writ of certiorari in the matter. The Company filed a friend-of-the-court brief with the U.S. Supreme Court on February 17, 2015, supporting the U.S. Solicitor General's and EnerNOC's position and urging the U.S. Supreme Court to grant certiorari. The eventual outcome of this proceeding could result in refunds of payments made for non-jurisdictional services and resettlement of wholesale markets but it is not possible to estimate the impact on the Company at this time.
State Regulation
In Texas, NRG's operations within the ERCOT footprint are not subject to rate regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by the PUCT, as well as to regulation by the NRC with respect to the Company's ownership interest in STP.
In New York, the Company's 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. Additionally, the NYSPSC has provided GenOn Bowline with a separate debt authorization of $1.488 billion.
In California, the Company's generation subsidiaries are subject to regulation by the CPUC with regard to certain non-rate aspects of the facilities, including health and safety, outage reporting and other aspects of the facilities' operations. Additionally, the competitiveness of many of NRG's new businesses is dependent on state competition and other policies.
        Nuclear Operations
NRG South Texas LP is a 44% owner of a joint undivided interest in STP, the other owners of STP being the City of Austin, Texas (16%) and the City Public Service Board of San Antonio (40%). STP Nuclear Operating Company, or STPNOC, was founded by the then-owners in 1973 to operate the plant and it is the operator licensee and holder of the Facility Operating Licenses NPF-76 and NPF-80. STPNOC is a nonstock, nonprofit, nonmember corporation. Each owner of STP appoints a board member (and the three directors then choose a fourth director who also serves as the chief executive officer of STPNOC). A participation agreement establishes an owners' committee with voting interests consistent with ownership interests.
As a holder of an ownership interest in STP, NRG South Texas LP is an NRC licensee and is subject to NRC regulation. The NRC license gives the Company the right only to possess an interest in STP but not to operate it. As a possession-only licensee, i.e., non-operating co-owner, the NRC's regulation of NRG South Texas LP is primarily focused on the Company's ability to meet its financial and decommissioning funding assurance obligations. In connection with the NRC license, the Company and its subsidiaries have a support agreement to provide up to $120 million to support operations at STP.
Decommissioning Trusts — Upon expiration of the operating 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 South Texas LP, 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 and AEP collect, through rates or other authorized charges to their electric utility customers, amounts designated for funding NRG South Texas LP's portion of the decommissioning of the facility. NRG South Texas LP filed a decommissioning cost rate case with the PUCT in 2013 based upon a third party cost study and assuming a twenty year license extension, which resulted in a decrease in the rate of collections. The PUCT approved the rate changes. See also Item 15 — Note 6, Nuclear Decommissioning Trust Fund, to the Consolidated Financial Statements for additional discussion.

24

                                                                                     

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 South Texas LP'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.
Nuclear Regulatory Commission Near-Term 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. Among other things, the Task Force required each operator to conduct a review of seismic and flooding risks (beyond the design license basis). STPNOC’s analysis confirmed the design adequacy and determined that no other actions are needed with respect to these risks. In conducting its review, STPNOC followed the guidance in the “Seismic Evaluation Guidance: Screening, Prioritization, and Implementation Details (SPID) for the Resolution of Fukushima Near-Term Task Force Recommendation 2.1: Seismic” report published by the Electric Power Research Institute.
Other responsive actions include installation of additional safety-related, redundant cooling systems, hardening of spent fuel pool instrumentation, improved emergency communications and increased responsive staffing, and the establishment of two FLEX (Flexible Emergency Response Equipment) sites serving the entire industry, all of which are on track to meet the NRC’s timetable for completion by the end of 2015. With respect to STP, the estimated total cost for the currently identified required tasks is projected to be less than $40 million, allocated among the three owners, such project being approximately 75% completed by year end in 2014. Until further action is taken by the NRC (including issuance of actions required in response to Tier 2 and 3 recommendations), the Company cannot definitively predict the impact of any additional recommendations by the Task Force and could be required to make additional investments at STP Units 1 and 2.
Nuclear Regulatory Commission Approves Final Rule on Storage of Spent Fuel — On August 26, 2014, the NRC revised its generic determination regarding the environmental impacts of the continued storage of spent nuclear fuel beyond a reactor’s licensed life for operation and prior to ultimate disposal and approved a final rule. Upon the effective date of the final rule, the NRC lifted its suspension of final licensing actions on nuclear power plant licenses and renewals.
Regional Regulatory Developments
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.
East Region
PJM
New Jersey and Maryland's Generator Contracting Programs — The New Jersey Board of Public Utilities and the Maryland Public Service Commission awarded long-term power purchase contracts to generation developers to encourage the construction of new generation capacity in the respective States. The constitutionality of the long-term contracts was challenged and the U.S. District Court for the District of New Jersey (in an October 25, 2013, decision) and the U.S. District Court for the District of Maryland (in an October 24, 2013, decision) found that the respective contracts violated the Supremacy Clause of the U.S. Constitution and were preempted. On June 30, 2014, the U.S. Court of Appeals for the Fourth Circuit affirmed the Maryland District Court's decision. On September 11, 2014, the U.S. Court of Appeals for the Third Circuit affirmed the New Jersey District Court's decision. Various parties have petitioned the U.S. Supreme Court for review of both cases. Any U.S. Supreme Court action may affect future capacity prices in PJM.
Capacity Replacement — On March 10, 2014, PJM filed at FERC to limit speculation in the forward capacity auction. Specifically, PJM proposed tariff changes that are designed to ensure that only capacity resources that are reasonably expected to be provided as a physical resource by the start of the delivery year can participate in the Base Residual Auction. These changes include the addition of a replacement capacity adjustment charge that is intended to remove the incentive to profit from replacing capacity commitments, an increase in deficiency penalties for non-performance, and a reduction in the number of incremental auctions from three to one. On May 9, 2014, FERC rejected PJM’s proposed changes to address replacement capacity and incremental auction design, but established a Section 206 proceeding and technical conference to find a just and reasonable outcome. On August 18, 2014, PJM requested that FERC defer further action in the proceeding. Since the request, FERC has taken no action. The Section 206 proceeding and technical conference could have a material impact on future PJM capacity prices.

25

                                                                                     

Capacity Performance Proposal — On December 14, 2014, PJM requested FERC approval to substantially revamp its capacity market. If approved by FERC, future annual capacity auctions would procure two categories of capacity resources: “Capacity Performance” resources and “Base Capacity” resources. Under the proposal, PJM would institute substantial new performance penalties on capacity performance resources that do not perform in real time during specified periods of high demand and substantially modify capacity bidding rules. Should the proposal be approved by FERC, it is likely to have a material impact on future PJM capacity prices.
Capacity Import Limits — On April 22, 2014, FERC approved PJM’s proposal to add a limit on the amount of capacity from external resources that PJM can reliably import into PJM. The capacity import limit will be in effect for the 2017/2018 Base Residual Auction, may decrease the amount of capacity imports allowed into PJM as compared to recent auctions, and could have a material impact on future PJM capacity prices. On January 22, 2015, FERC denied rehearing.
Reactive Power — On November 20, 2014, FERC issued an Order to Show Cause under FPA Section 206 directing PJM to either revise its tariff to provide that a generation or non-generation resource owner will no longer receive reactive power capability payments after it has deactivated its unit and to clarify the treatment of reactive power capability payments for units transferred out of a fleet or show cause why it should not be required to do so. On December 22, 2014, PJM filed proposed tariff changes, and the matter remains pending at FERC. NRG’s reactive power revenues may change as a result of this proceeding.
Recovery of Costs of Capacity Agreements Secured Outside RPM Auctions — On December 24, 2014, PJM submitted proposed revisions to the tariff to permit it to enter into and recover the costs of capacity agreements secured outside the RPM for the specific purpose of alleviating resource adequacy concerns during the 2015/2016 delivery year. On February 20, 2015, FERC rejected PJM's filing without prejudice to PJM refiling a fully specified and justified proposal.
Demand Response Operability — On May 9, 2014, FERC largely accepted PJM’s proposed changes on demand response operability in an attempt to enhance the operational flexibility of demand response resources during the operating day. The approval of these changes will likely limit the amount of demand response resources eligible to participate in PJM. The matter is pending rehearing at FERC.
PJM “Stop Gap” Demand Response Filing — On January 14, 2015, PJM filed to implement “stop gap” rules governing the participation of demand response in the upcoming capacity auction (for the 2018/2019 delivery year), which will take effect only if the U.S. Supreme Court denies certiorari of the EPSA v. FERC decision.  Under the new rules, PJM would prohibit demand response from participating in PJM’s capacity auction as supply-side resources.  Instead, PJM proposes to create a new product, termed “Wholesale Load Reduction,” that would allow LSEs to bid reductions in demand, backed by physical demand response resources, into the auction.  Demand response resources participating as Wholesale Load Reduction would have a comparable impact on capacity clearing prices as demand response participating as supply, on a megawatt for megawatt basis.  The Company is opposing PJM’s proposal. 

MOPR Litigation 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 Reliability Pricing Model capacity market, as well as PJM's subsequent submission seeking revisions to the capacity market design, in particular the MOPR. In its order, FERC generally strengthened the MOPR and the protections against market price distortion from out-of-market generation. On February 18, 2014, the Third Circuit Court of Appeals affirmed FERC's order.
MOPR Revisions On December 7, 2012, PJM filed comprehensive revisions to its MOPR rules at FERC.  On May 2, 2013, FERC accepted PJM's proposal in part, and rejected it in part.  Among other things, FERC approved the portions of the PJM proposal that exempt many new entrants from MOPR rules, including projects proposed by merchant generators, public power entities and certain self-supply entities.  This exemption is subject to certain conditions designed to limit the financial incentive of such entities to suppress market prices.  However, FERC rejected PJM's proposal to eliminate the unit specific review process and instead directed PJM to continue allowing units to demonstrate their actual costs and revenues and bid into the auction at that price.  On June 3, 2013, the Company filed a request for rehearing of the FERC order and subsequently protested the manner in which PJM proposed to implement the FERC order. These challenges are both pending.
New England
Performance Incentive Proposal — On January 17, 2014, ISO-NE filed at FERC to revise its forward capacity market, or FCM, by making a resource’s FCM compensation dependent on resource output during short intervals of operating reserve scarcity. The ISO-NE proposal would replace the existing shortage event penalty structure with a new performance incentive, or PI, mechanism, resulting in capacity payments to resources that would be the combination of two components: (1) a base capacity payment and (2) a performance payment or charge. The performance payment or charge would be entirely dependent upon the resource’s delivery of energy or operating reserves during scarcity conditions, and could be larger than the base payment.

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On May 30, 2014, FERC found that most of the provisions in the ISO-NE proposal, with modifications, together with an increase to the reserve constraint penalty factors, provided a just and reasonable structure. FERC instituted a proceeding for further hearings and required ISO-NE to make a compliance filing to modify its proposal and adopt the increases to the reserve constraint penalty factors. The matter is pending rehearing at FERC.
FCM Rules for 2014 Forward Capacity Auction — On February 28, 2014, ISO-NE filed the results of FCA #8 with FERC. On September 16, 2014, FERC issued a notice stating that the FCA #8 results would go into effect by operation of law. Several parties requested rehearing of FERC’s notice, which was rejected by FERC on procedural grounds. The matter was appealed to the U.S. Court of Appeals for the District of Columbia Circuit and remains pending.
NEPGA Complaint — On October 31, 2013, NEPGA filed a complaint against ISO-NE alleging that the tariff-set capacity prices during circumstances termed Insufficient Competition and Inadequate Supply and the tariff rules known as the Capacity Carry Forward Rule, components of the FCM, created unreasonable and unduly discriminatory price disparities between new and existing capacity resources. On November 25, 2013, ISO-NE submitted a proposal to raise the tariff-set administrative prices to $7.025/kW-month for Forward Capacity Auction 8. On January 24, 2014, FERC accepted ISO-NE’s proposal to revamp its Insufficient Supply and Insufficient Competition rules, which resulted in a declaration of the Insufficient Competition condition and a $7.025/kW-month price to all existing resources. On February 24, 2014, NEPGA filed a request for rehearing. On January 30, 2015, NEPGA’s request for rehearing was denied.
Sloped Demand Curve Filing — On May 30, 2014, FERC accepted the proposed tariff revisions discussed in the April 1, 2014 ISO-NE filing at FERC regarding the establishment of a sloped demand curve for use in the ISO-NE Forward Capacity Market. The accepted tariff changes include extending the period during which a market participant can lock-in the capacity price for a new resource from five to seven years, establishing a limited exemption for the buyer-side market mitigation rules for a set amount of renewable resources, and eliminating the administrative pricing rules. The shift away from the current vertical demand curve and accompanying proposed changes could have a material impact on the capacity prices in future auctions. The matter is still subject to rehearing at FERC.
New York
Demand Curve Reset and the Lower Hudson Valley Capacity Zone — On May 27, 2014, FERC denied rehearing and phase-in requests regarding its August 13, 2013 order on the creation of the Lower Hudson Valley Capacity Zone. The NYISO had previously approved the creation of a new Lower Hudson Valley Capacity Zone in New York, as part of the NYISO’s triennial adjustment of its capacity market parameters for the 2014-2017 periods. The State of New York, NYSPSC and Central Hudson Gas & Electric Corp. have challenged the FERC order before the U.S. Court of Appeals for the Second Circuit. The U.S. Court of Appeals for the Second Circuit held oral argument on September 12, 2014. The matter remains pending.
NYSPSC Order Rescinding Danskammer Retirement — On October 28, 2013, the NYSPSC took emergency action to rescind its approval for the 530 MW Danskammer facility to retire on October 30, 2013. The NYSPSC’s stated goal was to allow the facility to return to service in order to constrain rate increases in New York. The NYSPSC approved the emergency Order and granted an extension until March 17, 2014 for Helios Capital LLC to file its plan to operate or retire the unit. On March 28, 2014, the NYSPSC adopted the October 28, 2013 order as a permanent rule. The return to service of this facility may affect capacity prices received by NRG for its resources in the Rest-of-State Capacity Zone and the Lower Hudson Valley Capacity Zone.
Dunkirk Power Reliability Service On March 14, 2012, Dunkirk Power filed a notice with the NYSPSC of its intent to mothball the Dunkirk Station no later than September 10, 2012.  The effects of the mothball on electric system reliability were reviewed by Niagara Mohawk Power Corporation, d/b/a National Grid.  As a result of those studies, National Grid determined that the mothball of the Dunkirk Station would have a negative impact on the reliability of the New York transmission system and that portions of the Dunkirk Station may be retained for reliability purposes via a non-market compensation arrangement.  Additionally, on July 20, 2012, National Grid and Dunkirk Power agreed on the material terms for a bilateral RSS agreement and submitted those terms to the NYSPSC for rate recovery in National Grid's rates. On August 16, 2012, the NYSPSC approved terms and on August 27, 2012, Dunkirk Power and National Grid entered into the RSS agreement that began on September 1, 2012, and expired on May 31, 2013. In late 2012, National Grid issued a request for proposals with respect to its reliability need in the Dunkirk area for the two years beginning June 1, 2014. Dunkirk Power submitted a proposal and signed a second, two-year, contract on March 4, 2013 pursuant to which one unit (Unit 2) at Dunkirk will continue operating through May 31, 2015. The contract was submitted to the NYSPSC in March 2013 and approved in May 2013.
On July 12, 2012, Dunkirk Power filed a RMR agreement with FERC to protect the Company’s interests in the event National Grid and Dunkirk Power could not come to terms on a bilateral agreement for reliability support services. On February 19, 2015, FERC rejected the RMR agreement as unnecessary and clarified in a related docket that it was not intending to review either RSS agreement.

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Independent Power Producers of New York Complaint — On May 10, 2013, a generator trade association in New York filed a complaint at FERC against the NYISO. The generators asked FERC to direct the NYISO to require that capacity from existing generation resources that would have exited the market but for out-of-market payments under RMR type agreements be excluded from the capacity market altogether or be offered at levels no lower than the resources' going-forward costs. The complaints point to the recent reliability services agreements entered into between the NYSPSC and generators, including Dunkirk Power, as evidence that capacity market prices are being influenced by non-market considerations. The complainants seek to prevent below-cost offers from artificially suppressing prices in the New York Control Area Installed Capacity Spot Market Auction. The case is pending.
On March 25, 2014, the generators filed an Amended Complaint against the NYISO in light of the executed term sheet between Niagara Mohawk Power Corporation d/b/a National Grid and Dunkirk Power, which was filed at NYPSC in February 2014. Under the term sheet, National Grid and Dunkirk Power are to enter into a definitive agreement pursuant to which Dunkirk Power will undertake a gas addition project to enable Units 2-4 to run on natural gas in exchange for payments from National Grid over a 10-year term.
FERC Investigation of NYISO RMR Practices — On February 19, 2015, pursuant to Section 206 of the FPA, FERC found NYISO’s tariff to be unjust and unreasonable because it does not contain provisions governing the retention of and compensation to generating units for reliability. FERC ordered NYISO to adopt tariff provisions containing a proposed RMR rate schedule and pro forma RMR agreement within 120 days of the date of the FERC’s order. However, FERC clarified that NYISO’s RMR proposal will not require Dunkirk to enter into new pro forma agreements for the 2012 and 2013 RSS agreements.

Competitive Entry Exemption to Buyer-Side Mitigation Rules — On December 4, 2014, pursuant to Section 206 of the FPA, a group of New York transmission owners filed a complaint seeking a competitive entry exemption to the current NYISO Buyer-Side Mitigation rules. On December 16, 2014, TDI USA Holdings Corporation filed a complaint under Section 206 against the NYISO claiming that the NYISO’s application of the Mitigation Exemption Test under the Buyer-Side Mitigation Rules to TDI’s Champlain Hudson 1,000 MW transmission line project is unjust and unreasonable and seeks an exemption from the Mitigation Exemption Test. On February 26, 2015, FERC granted the complaint filed by the New York transmission owners and directed the NYISO to adopt a competitive entry exemption into its tariff within 30 days.  In a companion order issued on the same day, FERC rejected the TDI complaint on the grounds that TDI’s concerns were adequately addressed by FERC’s first order.  Allowing a competitive entry exemption significantly degrades protections against uneconomic entry into the New York markets.
Gulf Coast Region
ERCOT
Houston Import Project — At its April 8, 2014, meeting, the ERCOT Board endorsed a new 345 kV transmission line project designed to address purported reliability challenges related to congestion between north Texas into the Houston region. The proposed project would increase the import capability into the Houston area by adding a new 345 kV double-circuit line to achieve 2,988 MVA of emergency rating for each circuit, upgrading existing substations, and upgrading an existing 345 kV line to achieve 1,450 MVA of emergency rating. The target completion for the proposed project is 2018. On November 14, 2014, the PUCT denied a challenge by the Company and Calpine Corp. regarding ERCOT's endorsement of the project. The transmission owners have not yet initiated the licensing proceedings with the PUCT to obtain the authorization to move forward with the project (Certificate of Convenience and Necessity, or CCN).
Operating Reserve Demand Curve Implementation — At the direction of the PUCT, ERCOT implemented an operating reserve demand curve, known as ORDC, on June 1, 2014. ORDC simulates real-time co-optimization of energy and reserves and uses price adders during scarcity conditions to reflect price formation outcomes expected under real-time co-optimization. Under ORDC, real time energy price could rise to $9,000 per MWh during extreme scarcity events (due to value of lost load assumptions in the price curve), despite the current system wide offer cap of $7,000 per MWh.

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MISO
MISO RMR Practices — On July 5, 2013, AmerenEnergy Resources Generating Company, or Ameren, filed a complaint against MISO pertaining to the compensation for generators asked by MISO to provide service past their retirement date due to reliability concerns, or RMR Generators. Ameren asked FERC to require MISO to provide such generators their full cost of service as compensation and not merely cover the generator's incremental costs of operation going-forward costs. The Company supported the complaint. On July 22, 2014, FERC issued an Order denying the complaint in part and granting it in part. FERC found that the Tariff was unjust and unreasonable because it did not allow RMR Generators to obtain compensation for their fixed costs. The matter is pending rehearing.
MATS Waiver — Indianapolis Power and Light Company, DTE Electric Company, MidAmerican Energy Company, Duke Energy Indiana, Inc., Consumers Energy Company, and Wisconsin Power & Light Company each separately requested a limited, one-time waiver from their obligations to meet the Resource Adequacy Requirement in the MISO tariff, addressing an approximate six-week gap between the EPA’s MATS compliance deadline and the end of MISO’s 2015-2016 capacity planning year. The EPA’s MATS rules establish limits for HAPs emitted from, among other sources, existing and planned coal-fired generators and go into effect on April 16, 2015. Because the MISO capacity planning year runs from June 1 to May 31, there is a gap between the MATS-driven retirements in April and the MISO planning year in June. Any waiver of an LSE’s resource adequacy obligations would have a detrimental effect on the value of capacity in the MISO market.
On October 15, 2014, FERC granted Indianapolis Power and Light Company’s request for the limited, one-time waiver of MISO’s must-offer requirement and the requirement to purchase replacement capacity for the period of April 16, 2016 to May 31, 2016.

On November 7, 2014, FERC denied without prejudice Consumers Energy’s request for a limited waiver on the grounds that Consumers Energy failed to adequately demonstrate that the requested waiver would not cause undesirable consequences, such as harming third-parties. On November 18, 2014, Consumers Energy re-filed its request for a limited waiver. On February, 20, 2014, FERC granted Consumers Energy’s request. Also on that day, FERC granted DTE, MidAmerican, and Duke Energy’s requests for waivers. Wisconsin Power & Light’s request is still pending before FERC. Unlike the other entities’ requests of approximately six weeks, Wisconsin Power & Light’s request is for a five-month waiver based on a consent decree among the company, the EPA, and the Sierra Club.

Environmental Matters
NRG is subject to a wide range of environmental laws in the development, construction, ownership and operation of projects. These laws generally require governmental authorizations to build and operate power plants. Environmental laws have become increasingly stringent and NRG expects this trend to continue. The electric generation industry is likely to face new and more stringent requirements to address various emissions, including GHGs, as well as combustion byproducts, water discharge and use, and threatened and endangered species. In general, the Company expects future laws to require adding emissions controls or other environmental controls or to impose more restrictions on the operations of the Company's facilities, which could have a material effect on operations.
Federal Environmental Initiatives
Environmental Regulatory Landscape — A number of regulations with the potential to affect the Company and its facilities are in development or under review by the EPA: ESPS/NSPS for GHGs, NAAQS revisions and implementation and effluent guidelines. 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 (and any resulting legal challenges resolved).
Air 
The CAA and the resulting regulations (as well as similar state and local requirements) have the potential to affect air emissions, operating practices and pollution control equipment required at power plants. Under the CAA, the EPA sets NAAQS for certain pollutants including SO2, ozone, and PM2.5. Many of the Company's facilities are located in or near areas that are classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS have become more stringent and NRG expects that trend to continue. The Company expects increased regulation at both the federal and state levels of its air emissions and maintains a comprehensive compliance strategy to address these continuing and new requirements. Complying with increasingly stringent NAAQS may require the installation of additional emissions control equipment at some NRG facilities or retiring of units if installing such controls is not economical. Significant changes to air regulatory programs affecting the Company are described below.

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In December 2014, the EPA proposed making the NAAQS for ozone more stringent. The EPA anticipates promulgating a more stringent ozone NAAQS by October 2015. A more stringent NAAQS would obligate the states to develop plans to reduce NOx (an ozone precursor), which might affect some of the Company's units.
Cross-State Air Pollution Rule — In August 2011, the EPA finalized CSAPR, which was intended to replace CAIR starting in 2012. It was designed to address interstate SO2 and NOX emissions from certain power plants in the eastern half of the U.S. In September 2011, GenOn and others asked the U.S. Court of Appeals for the D.C. Circuit to stay and vacate CSAPR. In December 2011, the court stayed implementation of CSAPR and ordered the EPA to keep CAIR in place until the court could rule on the legal deficiencies alleged with respect to CSAPR. In August 2012, the D.C. Circuit Court vacated CSAPR but kept CAIR in place.  The EPA petitioned the U.S. Supreme Court seeking review of the D.C. Circuit's decision, which petition was granted. On April 29, 2014, the U.S. Supreme Court reversed and remanded the D.C. Circuit's decision. In October 2014, the D.C. Circuit lifted the stay of CSAPR. In response, the EPA issued an interim final rule in November 2014 to amend the CSAPR compliance dates. Accordingly, CSAPR replaced CAIR on January 1, 2015. On February 25, 2015, the D.C. Circuit held oral argument regarding several unresolved legal issues, and the Company expects a decision in the second quarter of 2015. While the Company cannot predict the final outcome of the ongoing litigation, the Company believes its investment in pollution controls and cleaner technologies coupled with planned plant retirements should leave the fleet well positioned for compliance.
MATS — In February 2012, the EPA promulgated standards to control emissions of HAPs from coal and oil-fired electric generating units. The rule established limits for mercury, non-mercury metals, certain organics and acid gases, which limits must be met beginning in April 2015 (with some units getting a 1-year extension). In November 2014, the U.S. Supreme Court agreed to review the D.C. Circuit decision that denied the petitions seeking to vacate MATS but the review will be limited to whether the EPA unreasonably refused to consider costs in determining whether it is appropriate to regulate hazardous air pollutants emitted by electric generating units. The oral argument in the Supreme Court is scheduled for March 2015.
In January 2014, the EPA re-proposed the NSPS for CO2 emissions from new fossil-fuel-fired electric generating units that had been previously proposed in April 2012. The re-proposed standards are 1,000 pounds of CO2 per MWh for large gas units and 1,100 pounds of CO2 per MWh for coal units and small gas units. Proposed standards are in effect until a final rule is published or another rule is re-proposed. In June 2014, the EPA proposed a rule that would require states to develop CO2 standards that would apply to existing fossil-fueled generating facilities. Specifically, the EPA proposed state-specific rate-based goals for CO2 emissions, as well as guidelines for states to follow in developing plans to achieve the state-specific goals. The EPA anticipates finalizing both of these rules in the summer of 2015.
The effects from federal, regional or state regulation of GHGs on the Company's financial performance will depend on a number of factors, including the regulatory design, level of GHG reductions, the availability 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.

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CO2 Emissions
NRG emits CO2 when generating electricity at most of its facilities. The graph presented below illustrates NRG's emissions of CO2 for 2012, 2013, and 2014. NRG anticipates reductions in its future emissions profile as the Company adds more renewable sources such as wind and solar, modernizes the fleet through repowering, improves generation efficiencies, and explores methods to capture CO2. By 2030, the Company seeks to reduce its CO2 emissions by 50%, using 2014 as a baseline. The Company's objective is to reduce its CO2 emissions by 90% by 2050.
 Byproducts, Wastes, Hazardous Materials and Contamination
In December 2014, the EPA released a pre-publication version of a final rule that when published in the Federal Register will regulate byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. In 2010, the EPA had proposed two alternatives. Under the first proposal, these byproducts would be regulated as solid wastes. Under the second proposal, these byproducts would have been regulated as “special wastes” in a manner similar to the regulation of hazardous waste with an exception for certain types of beneficial use of these byproducts. The second alternative would have imposed significantly more stringent requirements and materially increased the cost of disposal of coal combustion byproducts. The Company is evaluating the impact of the new rule on its results of operations, financial condition and cash flows.
Domestic Site Remediation Matters
Under certain federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products at the facility. NRG may also be responsible 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 during its operations. Further discussions of affected NRG sites can be found in Item 15 — Note 24, Environmental Matters, to the Consolidated Financial Statements.

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Nuclear Waste — The federal government's program to construct a nuclear waste repository at Yucca Mountain, Nevada was discontinued in 2010. Since 1998, the U.S. DOE has been in default of the federal government's obligations to begin accepting spent nuclear fuel, or SNF, and high-level radioactive waste, or HLW, under the U.S. Nuclear Waste Policy Act of 1982, or the Act. Owners of nuclear plants, including the owners of STP, had been required to enter 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 to license a spent fuel repository. Effective May 16, 2014, the U.S. DOE stopped collecting the fees.
On February 5, 2013, STPNOC entered into a settlement agreement with the U.S. DOE for payment of damages relating to the U.S. DOE's failure to accept SNF and HLW under the Act through December 31, 2013, which was extended through an addendum dated January 24, 2014, to December 31, 2016. There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the U.S., nor has the NRC licensed any such facilities. STPNOC currently stores all SNF generated by its nuclear generating facilities in on-site storage pools.  Since STPNOC's SNF storage pools do not have sufficient storage capacity for the life of the units, STPNOC is proceeding to construct dry cask storage capability on-site. STPNOC plans to continue to assert claims against the U.S. DOE for damages relating to the U.S. DOE's failure to accept SNF and HLW.
Effective October 20, 2014, the NRC issued its Continued Storage of Spent Nuclear Fuel rule that determined that licensees can safely store SNF at nuclear power plants beyond the original and renewed licensed operating life of the plants. The rule remains subject to legal challenges. Upon the effective date of the rule, the NRC lifted its suspension of licensing actions on nuclear power plants.
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.
Water 
Clean Water Act The Company is required under the CWA to comply with intake and discharge requirements, requirements for technological controls and operating practices. As with air quality regulations, federal and state water regulations are expected to impose additional and more stringent requirements or limitations in the future. This includes requirements governing cooling water intake structures, which are subject to regulation under section 316(b) of the CWA (the 316(b) regulations). In August 2014, EPA finalized the regulation (which had been proposed in 2011) regarding once through cooling from existing facilities to address impingement and entrainment of organisms. NRG anticipates that more stringent requirements will be incorporated into some of its water discharge permits over the next several years. NRG expects to comply with the anticipated requirements with a mix of intake and operational modifications.
Regional Environmental Issues
East Region
The EPA and various states have been investigating compliance of electric generating facilities with the pre-construction permitting requirements of the CAA known as “new source review,” or NSR. In 2007, Midwest Generation received an NOV from the EPA alleging that past work at Crawford, Fisk, Joliet, Powerton, Waukegan and Will County generating stations violated NSR and other regulations. These alleged violations are the subject of litigation described in Item 15 — Note 22, Commitments and Contingencies. In January 2009, GenOn received an NOV from the EPA alleging that past work at Keystone, Portland and Shawville generating stations violated regulations regarding NSR. In June 2011, GenOn received an NOV from the EPA alleging that past work at Avon Lake and Niles generating stations violated NSR. In December 2007, the NJDEP filed suit alleging that NSR violations occurred at the Portland generating station, which suit was resolved pursuant to a July 2013 Consent Decree. Additionally, in April 2013, the Connecticut Department of Energy and Environmental Protection issued four NOVs alleging that past work at oil-fired combustion turbines at the Torrington Terminal, Franklin, Branford and Middletown generating stations violated regulations regarding NSR.

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In 2008, the PADEP issued an NOV related to the Monarch mine located near the Cheswick generating facility. It has not been mined for many years. The Company's subsidiary discharged approved wastewaters into the Monarch mine including low-volume wastewater from the Cheswick generating facility and leachate collected from ash disposal facilities. The NOV addresses a permit requirement to pump a minimum water volume from the mine. On September 2, 2014, the Company's subsidiary that owns the Cheswick generating facility, the Commonwealth of Pennsylvania and the PADEP entered into a Consent Order and Agreement resolving the NOV. Pursuant to that Consent Order and Agreement, the Company's subsidiary will, among other things, cease wastewater discharges to the mine, construct a waste treatment facility and contribute $200,000 to the Indianola Mine Trust. The Company's subsidiary is currently planning to incur capital expenditures in connection with wastewater from Cheswick and leachate from ash disposal facilities.
In January 2006, NRG's Indian River Power LLC was notified that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program. On February 4, 2008, DNREC issued findings that no further action is required in relation to surface water and that a previously planned shoreline stabilization project would satisfactorily address shoreline erosion. The landfill itself required a Remedial Investigation and Feasibility Study to determine the type and scope of any additional required work. The DNREC approved the Feasibility Study in December 2012. In January 2013, DNREC proposed a remediation plan based on the Feasibility Study. The remediation plan was approved in October 2013. The cost of completing the work required by the approved remediation plan is consistent with amounts previously budgeted. On May 29, 2008, DNREC requested that NRG's Indian River Power LLC participate in the development and performance of a Natural Resource Damage Assessment at the Burton Island Old Ash Landfill. NRG is currently working with DNREC and other trustees to close out the assessment process.
Maryland Environmental Regulations — In October 2014, the MDE released a draft of a proposed regulation regarding NOx emissions from coal-fired electric generating units. The MDE draft regulation was proposed in the Maryland Register in December 2014. If finalized as proposed, the regulation would require by June 2020 the Company (at each of the three Dickerson coal-fired units and the Chalk Point coal-fired unit that does not have an SCR) to (1) install and operate an SCR; (2) retire the unit; or (3) convert the fuel source from coal to natural gas. The implementation of the MDE regulation could negatively affect certain of the Company’s coal-fired units in Maryland.
RGGI — The Company operates generating units in Connecticut, Delaware, Maryland, Massachusetts, and New York that are subject to RGGI, which is a regional cap and trade system. In 2013, each of these states finalized a rule that reduced and will continue to reduce the number of allowances, which the Company believes will increase the price of each allowance. These new rules could adversely impact NRG's results of operations, financial condition and cash flows.
Gulf Coast Region
In 2009, the U.S. DOJ, on behalf of the EPA, and later the Louisiana Department of Environmental Quality on behalf of the state of Louisiana, sued LaGen in federal district court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant. On March 6, 2013, the court entered a Consent Decree resolving the matter. In addition to a fine of $3.5 million and mitigation projects totaling $10.5 million, the Consent Decree includes: (i) annual emission caps for NOx and SO2; (ii) installation of selective non-catalytic reduction on Units 1, 2 and 3 by May 1, 2014; (iii) installation of dry sorbent injection on Unit 1 by April 15, 2015 followed by a further reduction in SO2 in March 2025; (iv) conversion of Unit 2 to natural gas; and (v) surrender of any excess allowances associated with the NRG owned portion of the plant. For further discussion of this matter, refer to Item 15 Note 22, Commitments and Contingencies.
Environmental Capital Expenditures
Based on current (and in some cases proposed) rules, technology and preliminary plans based on some proposed rules, NRG estimates that environmental capital expenditures from 2015 through 2019 required to comply with environmental laws will be approximately $641 million which includes $58 million for GenOn and $464 million for EME. These costs are primarily associated with (i) controls to satisfy MATS and recent NSR settlement at Big Cajun II; (ii) controls to satisfy MATS at W.A. Parish, Limestone and Conemaugh; (iii) NOx controls for Sayreville and Gilbert; and (iv) DSI/ESP upgrades at Waukegan and Powerton to satisfy the IL CPS and the Joliet gas conversion. NRG continues to explore cost-effective compliance alternatives to further reduce costs.
NRG's current contracts with the Company's rural electrical customers in the Gulf Coast region allow for recovery of a portion of the region's capital costs once in operation, along with a capital return incurred by complying with any change in law, including interest over the asset life of the required expenditures. The actual recoveries will depend, among other things, on the timing of the completion of the capital projects and the remaining duration of the contracts.

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Customers
NRG sells to a wide variety of customers. No individual customer accounted for 10% or more of NRG's total revenue in 2014. The Company owns and operates power plants to generate and sell power to wholesale customers such as utilities and other intermediaries. The Company also directly sells to end-use customers in the residential, commercial and industrial sectors.
Employees
As of December 31, 2014, NRG had 9,806 employees, approximately 31% of whom were covered by U.S. bargaining agreements. During 2014, 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 Exchange Act are available free of charge through the Company's website, www.nrg.com, as soon as reasonably practicable after they are electronically filed with, or furnished to, the 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 have traditionally had higher variable costs than NRG's coal-fired power plants. Historically, this has allowed the Company's coal generation assets to earn attractive operating margins compared to plants fueled by natural gas. Decreases in natural gas prices have resulted in a corresponding decrease in the market price of power that has significantly reduced the operating margins of the Company's baseload generation assets and may 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 coal and nuclear 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, distributed generation, and more efficient end-use technologies;
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.
Such factors have affected the Company's wholesale power operating results in the past and will continue 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, riverways 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 no fuel is available at any price or 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 coal and nuclear 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.
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 coal and nuclear facilities has been sold forward under fixed price power sales contracts through 2015 and the Company also sells forward the output from its intermediate and peaking facilities when it deems it commercially advantageous to do so. The Company also sells fixed price gas as a proxy for power. 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.

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In the Gulf Coast region, NRG has long-term contracts with rural cooperatives that require it to serve all of the cooperatives' requirements at prices for energy that generally reflect the cost of coal-fired generation.  On December 19, 2013, the Entergy region joined the MISO RTO, which employs a two settlement market in which NRG submits bids for energy to cover its load obligations and submits offers to sell energy from its resources.  Given the “full requirements” obligation contained in the cooperative contracts, and the possibility of unplanned forced outages of its generation, NRG may be exposed to locational market prices as a net buyer of energy for certain periods, which could have a negative impact on NRG's financial returns from its Gulf Coast region.
NRG's trading operations and 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.
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.

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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 FASB, 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 the Company's 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 may have greater liquidity, greater access to credit and other financial resources, lower cost structures, more effective risk management policies and procedures, greater ability to incur losses, longer-standing relationships with customers, greater potential for profitability from ancillary services or greater flexibility in the timing of their sale of generation capacity and ancillary services than NRG does.
NRG's competitors may be able to respond more quickly to new laws or regulations or emerging technologies, or to devote greater resources to the construction, expansion or refurbishment of their power generation facilities than NRG can. In addition, current and potential competitors may make strategic acquisitions or establish cooperative relationships among themselves or with third parties. Accordingly, it is possible that new competitors or alliances among current and new competitors may emerge and rapidly gain significant market share. There can be no assurance that NRG will be able to compete successfully against current and future competitors, and any failure to do so would have a material adverse effect on the Company's business, financial condition, results of operations and cash flow.
Operation of power generation facilities involves significant risks and hazards customary to the power industry that could have a material adverse effect on NRG's revenues and results of operations, and 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.

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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 (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 significantly modifies a unit, 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 CAA, which would likely result in substantial additional capital expenditures.
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 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:
inability to receive loan guarantees, funding or cash grants;
delays in obtaining necessary permits and licenses;
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.

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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 the Company losing its 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.
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.

40

                                                                                     

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 or at comparable prices.
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 PPAs, the Company would sell its plants' power at market prices. If the Company is unable to enter into replacement fuel or fuel transportation purchase agreements, NRG would seek to purchase the Company's fuel requirements at market prices, exposing the Company to market price volatility and the risk that fuel and transportation may not be available during certain periods at any price.
The failure of any supplier or customer to fulfill its contractual obligations to NRG could have a material adverse effect on the Company's financial results. Consequently, the financial performance of the Company's facilities is dependent on the credit quality of, and continued performance by, suppliers and customers.
NRG relies on power transmission facilities that it does not own or control and that are subject to transmission constraints within a number of the Company's core regions. If these facilities fail to provide NRG with adequate transmission capacity, the Company may be restricted in its ability to deliver wholesale electric power to its customers and the Company may either incur additional costs or forego revenues. Conversely, improvements to certain transmission systems could also reduce revenues.
NRG depends on transmission facilities owned and operated by others to deliver the wholesale power it sells from the Company's power generation plants to its customers. If transmission is disrupted, or if the transmission capacity infrastructure is inadequate, NRG's ability to sell and deliver wholesale power may be adversely impacted. If a region's power transmission infrastructure is inadequate, the Company's recovery of wholesale costs and profits may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have sufficient incentive to invest in expansion of transmission infrastructure. The Company also cannot 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.
One of the Company's subsidiaries is a publicly traded corporation, NRG Yield, Inc., which may involve a greater exposure to legal liability than the Company's historic business operations.
One of the Company's subsidiaries is NRG Yield, Inc., a publicly traded corporation. NRG's controlling interest in NRG Yield, Inc. and the position of certain of its executive officers on the Board of Directors of NRG Yield, Inc. may increase the possibility of claims of breach of fiduciary duties including claims of conflicts of interest related to NRG Yield, Inc. Any liability resulting from such claims could have a material adverse effect on NRG's future business, financial condition, results of operations and cash flows.

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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.
NRG may be unable to integrate the operations of acquired entities in the manner expected.
NRG enters into acquisitions that result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of these acquisitions depends on whether the businesses can be integrated into NRG in an efficient and effective manner. The integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of NRG's businesses, processes and systems or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect the Company's ability to achieve the anticipated benefits of the acquisitions. NRG may have difficulty addressing possible differences in corporate cultures and management philosophies. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect NRG's future business, financial condition, operating results and prospects.
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 U.S. federal, state and local laws and foreign laws. 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. 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. FERC's orders that grant NRG's generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if FERC subsequently determines that NRG can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, NRG's market-based sales are subject to certain market behavior rules, and if any of NRG's generating and power marketing companies were deemed to have violated one of those rules, they are subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority. If NRG's generating and power marketing companies were to lose their market-based rate authority, such companies would be required to obtain FERC's acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates NRG charges for power from its facilities.

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Substantially all of the Company's generation assets are also subject to the reliability standards promulgated by the designated Electric Reliability Organization (currently NERC) and approved by FERC. If NRG fails to comply with the mandatory reliability standards, NRG could be subject to sanctions, including substantial monetary penalties and increased compliance obligations. 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 continuously monitors the ongoing efforts of the CFTC to implement the Dodd-Frank Act and to otherwise revise the rules and regulations applicable to the futures and over-the-counter derivatives markets. The CFTC’s remaining efforts in this regard concern, among other things, the implementation of the Volcker rule and of other new rules relating to margin collateral and position limits for futures and other derivatives.  Such changes could negatively impact NRG’s ability to hedge its portfolio in an efficient, cost-effective manner by, among other things, potentially limiting NRG’s ability to utilize non-cash collateral for derivatives transactions and decreasing liquidity in the forward commodity and derivatives markets.  The Company expects that, in 2015, the CFTC will further clarify the scope of the Dodd-Frank Act and issue additional final rules.  
Government regulations providing incentives for renewable generation could change at any time and such changes may adversely impact NRG's business, revenues, margins, results of operations and cash flows.
The Company's growth strategy depends in part on government policies that support renewable generation and enhance the economic viability of owning renewable electric generation assets. Renewable generation assets currently benefit from various federal, state and local governmental incentives such as ITCs, cash grants in lieu of ITCs, loan guarantees, RPS programs, modified accelerated cost-recovery system of depreciation and bonus depreciation. For example, the U.S. Internal Revenue Code of 1986, as amended, provides an ITC of 30% of the cost-basis of an eligible resource, including solar energy facilities placed in service prior to the end of 2016, which percentage is currently scheduled to be reduced to 10% for solar energy systems placed in service after December 31, 2016.
Many states have adopted RPS programs mandating that a specified percentage of electricity sales come from eligible sources of renewable energy. However, the regulations that govern the RPS programs, including pricing incentives for renewable energy, or reasonableness guidelines for pricing that increase valuation compared to conventional power (such as a projected value for carbon reduction or consideration of avoided integration costs), may change. If the RPS requirements are reduced or eliminated, it could lead to fewer future power contracts or lead to lower prices for the sale of power in future power contracts, which could have a material adverse effect on the Company's future growth prospects.
Such material adverse effects may result from decreased revenues, reduced economic returns on certain project company investments, increased financing costs, and/or difficulty obtaining financing. Furthermore, the ARRA included incentives to encourage investment in the renewable energy sector, such as cash grants in lieu of ITCs, bonus depreciation and expansion of the U.S. DOE loan guarantee program. It is uncertain what loan guarantees may be made by the U.S. DOE loan guarantee program in the future. In addition, the cash grant in lieu of ITCs program only applies to facilities that commenced construction prior to December 31, 2011, which commencement date may be determined in accordance with the safe harbor if more than 5% of the total cost of the eligible property was paid or incurred by December 31, 2011.
If the Company is unable to utilize various federal, state and local government incentives to acquire additional renewable assets in the future, or the terms of such incentives are revised in a manner that is less favorable to the Company, it may suffer a material adverse effect on the business, financial condition, results of operations and cash flows.
    

43

                                                                                     

Certain of NRG's long-term bilateral contracts with state governments could be declared invalid by a court of competent jurisdiction.

A significant portion of NRG’s revenues are derived from long-term bilateral contracts with state-regulated utilities. Other state-regulated contracts, to which the Company is not a party, are being challenged in federal court and have been declared unconstitutional on the grounds that the rate for energy and capacity established by the state-regulated contracts impermissibly conflict with the rate for energy and capacity established by FERC. To date, federal district courts in New Jersey and Maryland have struck down contracts on similar grounds. The U.S. Court of Appeals for the Fourth Circuit upheld the Maryland court decision, while the U.S. Court of Appeals for the Third Circuit upheld the New Jersey decision. If certain of the Company's state-regulated agreements with utilities are held to be invalid, the Company may be unable to replace such contracts, which could have a material adverse effect on the Company's business, financial condition, results of operations and cash flows.

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, ownership and operation of STP, of which NRG indirectly owns a 44% 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. The current facility operating licenses for STP expire on August 20, 2027 (Unit 1) and December 15, 2028 (Unit 2). STP has applied for the renewal of such licenses for a period of 20 years beyond the expirations of the current licenses. The NRC may decline to issue such renewals or may modify or otherwise condition such license renewals in a manner that results in substantial increased capital or operating costs, or that otherwise results in a material adverse effect on STP’s economics and NRG’s results of operations, financial condition or cash flow.
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. The on-going industry response to the accident at Fukushima is an example of an external event with the potential for requiring significant increases in capital expenditures in order to comply with the yet-to-be-determined consequences of, and regulatory response to, an adverse event, such as mitigating steps that might be required after the seismic re-analysis in progress at all nuclear generating facilities. Additionally, aging equipment may require more capital expenditures to keep each of these nuclear power plants operating efficiently.  This equipment is also likely to 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.  STP will 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 Regulatory Matters — Nuclear Operations - Decommissioning Trusts and Item 1 — Environmental Matters — Federal Environmental Initiatives — Nuclear Waste for further discussion. Costs associated with these risks could be substantial and could have a material adverse effect on NRG's results of operations, financial condition or cash flow to the extent not covered by the Decommissioning Trusts or recovered from ratepayers. 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.
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. See also Item 15 Note 22, Commitments and Contingencies, Nuclear Insurance. 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.

44

                                                                                     

NRG is subject to environmental laws 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 is subject to the environmental laws of foreign and U.S., federal, state and local authorities. The Company must comply with numerous environmental laws and obtain numerous governmental permits and approvals to build and 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 generally have become more stringent, and the Company expects this trend to continue.
Policies at the national, regional and state levels to regulate GHG emissions, as well as climate change, could adversely impact NRG's results of operations, financial condition and cash flows.
NRG's GHG emissions for 2014 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 availability 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 RGGI, which is a regional cap and trade system. In 2013, each of these states finalized a rule that reduced and will continue to reduce the number of allowances, which the Company believes will increase the price of each allowance. These new rules could adversely impact NRG's results of operations, financial condition and cash flows.
California has a CO2 cap and trade program for electric generating units greater than 25 MW. The impact on the Company depends on the cost of the allowances and the ability to pass these costs through to customers.
In January 2014, the EPA re-proposed the NSPS for CO2 emissions from new fossil-fuel-fired electric generating units that had been previously proposed in April 2012. The re-proposed standards are 1,000 pounds of CO2 per MWh for large gas units and 1,100 pounds of CO2 per MWh for coal units and small gas units. Proposed standards are in effect until a final rule is published or another rule is re-proposed. In June 2014, the EPA proposed a rule that would require states to develop CO2 standards that would apply to existing fossil-fueled generating facilities. Specifically, the EPA proposed state-specific rate-based goals for carbon dioxide emissions, as well as guidelines for states to follow in developing plans to achieve the state-specific goals. The EPA anticipates finalizing both of these rules in the summer of 2015.
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 affected.
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, 2014, approximately 31% 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. Although NRG's ability to procure such labor is uncertain, contingency staffing planning is completed as part of each respective contract negotiations. 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.

45

                                                                                     

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 negative 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 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. Furthermore, financial and other restrictive covenants contained in any project level subsidiary debt may limit the ability of NRG to receive distributions from such subsidiary. NRG's failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of all of the Company's indebtedness.
In addition, NRG's ability to arrange financing, either at the corporate level, a non-recourse project-level subsidiary or otherwise, 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.

46

                                                                                     

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.
A valuation allowance may be required for NRG's deferred tax assets.
A valuation allowance may need to be recorded against deferred tax assets that the Company estimates are more likely than not to be unrealizable, based on available evidence including cumulative and forecasted pretax book earnings at the time the estimate is made. A valuation allowance related to deferred tax assets can be affected by changes to tax laws, statutory tax rates and future taxable income levels. In the event that the Company determines that it would not be able to realize all or a portion of its net deferred tax assets in the future, the Company would reduce such amounts through a charge to income tax expense in the period in which that determination was made, which could have a material adverse impact on the Company's financial condition and results of operations.
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 its retail businesses supply requirements, the retail businesses purchase a significant portion of their supply requirements from third parties. As a result, financial performance depends on the 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 the retail business' power supply costs rise at a greater rate than the rates it charges to customers. The price of power supply purchases associated with the retail business' 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 NRG's retail businesses are dependent. Power supply may be sold at a loss if these events cause a significant loss of retail customer load.
NRG Home's retail businesses may lose a significant number of retail customers due to competitive marketing activity by other retail electricity providers which could adversely affect the financial performance of NRG Home's retail businesses.
NRG Home's retail businesses face competition for customers. Competitors may offer lower prices and other incentives, which may attract customers away from NRG Home's 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, NRG Home's 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 Home and its retail businesses.

47

                                                                                     

NRG Home'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 NRG Home's retail businesses.
NRG Home's 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. NRG Home's 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 NRG Home's retail businesses. If a significant breach occurred, the reputation of NRG Home and its retail businesses may be adversely affected, customer confidence may be diminished, or NRG Home and its 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.
NRG Home’s business is subject to changing state rules and regulations that could have a material impact on the profitability of its business lines.
NRG Home’s competitiveness is partially dependent on state regulatory policies that establish the structure, rules, terms and conditions on which services are offered to retail customers.  These state policies, including net metering or RPS programs, can make it more or less expensive for retail customers to supplement or replace their reliance on grid power, such as with rooftop solar or other NRG Home offerings.  NRG Home has limited ability to influence development of these policies and its business model may be more or less effective, depending on changes to the regulatory environment.   
 The Company has made investments, and may continue to make investments, in new business initiatives predominantly focused on consumer products and in markets that may not be successful, may not achieve the intended financial results or may result in product liability and reputational risk that could adversely affect the Company.
NRG continues to pursue growth in its existing businesses and markets and further diversification across the competitive energy value chain. NRG is continuing to pursue investment opportunities in renewables, residential solar, consumer products and distributed generation. Such initiatives may involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered in the diligence performed prior to launching an initiative or entering a market.

As part of these initiatives, the Company may be liable to customers for any damage caused to customers’ homes, facilities, belongings or property during the installation of Company products and systems, such as residential solar systems and mass market back-up generators. In addition, shortages of skilled labor for Company projects could significantly delay a project or otherwise increase its costs. The products that the Company sells or manufactures may expose the Company to product liability claims relating to personal injury, death, or environmental or property damage, and may require product recalls or other actions. Although the Company maintains liability insurance, the Company cannot be certain that its coverage will be adequate for liabilities actually incurred or that insurance will continue to be available to the Company on economically reasonable terms, or at all. Further, any product liability claim or damage caused by the Company could significantly impair the Company’s brand and reputation, which may result in a failure to maintain customers and achieve the Company’s desired growth initiatives in these new businesses.

The Company's international operations are exposed to political and economic risks, commercial instability and events beyond the Company's control in the countries in which it operates.
The Company's international operations are dependent upon products manufactured, purchased and sold in the U.S. and internationally, including in countries with political and economic instability. In some cases, these countries have greater political and economic volatility and greater vulnerability to infrastructure and labor disruptions than in NRG's other markets. The Company's business could be negatively impacted by adverse fluctuations in freight costs, limitations on shipping and receiving capacity, and other disruptions in the transportation and shipping infrastructure at important geographic points of exit and entry for the Company's products. Operating and seeking to expand business in a number of different regions and countries exposes the Company to a number of risks, including:
multiple and potentially conflicting laws, regulations and policies that are subject to change;
imposition of currency restrictions on repatriation of earnings or other restraints;
imposition of burdensome tariffs or quotas;
national and international conflict, including terrorist acts; and
political and economic instability or civil unrest that may severely disrupt economic activity in affected countries.
The occurrence of one or more of these events may negatively impact the Company's business, results of operations and financial condition.

48

                                                                                     

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Annual Report on Form 10-K of NRG Energy, Inc., or NRG or the Company, 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 Securities Exchange Act of 1934, as amended, or 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'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 GHG 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 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 develop and build new power generation facilities, including new solar projects;
NRG's ability to implement its strategy;
NRG's ability to achieve its strategy of regularly returning capital to stockholders;
NRG's ability to obtain and maintain retail market share;
NRG's ability to successfully evaluate investments and achieve intended financial results in new business and growth initiatives;
NRG's ability to successfully integrate, realize cost savings 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.

49

                                                                                     

Item 2 — Properties
Listed below are descriptions of NRG's interests in facilities, operations and/or projects owned or leased as of December 31, 2014. The MW figures provided represent nominal summer net megawatt capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units as of December 31, 2014. The following table summarizes NRG's power production and cogeneration facilities by region:
Name and Location of Facility
Power Market
 
% Owned(a)(b)(c)
 
Net
Generation
Capacity (MW) (d)
 
Primary Fuel-type
NRG Business:
 
 
 
 
 
 
 
Gulf Coast Region
 
 
 
 
 
 
 
Bayou Cove, Jennings, LA
MISO
 
100.0
 
225

 
Natural Gas
Big Cajun I, Jarreau, LA
MISO
 
100.0
 
430

 
Natural Gas
Big Cajun II, New Roads, LA (e)
MISO
 
85.8
(f) 
1,496

 
Coal
Cedar Bayou, Baytown, TX
ERCOT
 
100.0
 
1,495

 
Natural Gas
Cedar Bayou 4, Baytown, TX
ERCOT
 
50.0
 
249

 
Natural Gas
Choctaw, French Camp, MS
MISO
 
100.0
 
800

 
Natural Gas
Cottonwood, Deweyville, TX
MISO
 
100.0
 
1,263

 
Natural Gas
Greens Bayou, Houston, TX
ERCOT
 
100.0
 
651

 
Natural Gas
Gregory, Corpus Christi, TX
ERCOT
 
100.0
 
388

 
Natural Gas
Limestone, Jewett, TX
ERCOT
 
100.0
 
1,689

 
Coal
Osceola, Holopaw, FL (g)
FRCC
 
100.0
 
463

 
Natural Gas
San Jacinto, LaPorte, TX
ERCOT
 
100.0
 
162

 
Natural Gas
South Texas Project, Bay City, TX (h)
ERCOT
 
44.0
 
1,176

 
Nuclear
Sterlington, LA
MISO
 
100.0
 
176

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

 
Natural Gas
W. A. Parish, Thompsons, TX
ERCOT
 
100.0
 
2,504

 
Coal
W. A. Parish, Thompsons, TX 
ERCOT
 
100.0
 
1,220

 
Natural Gas
 
Total net Gulf Coast Region
 
15,412

 
 
East Region
 
 
 
 
 
 
 
Arthur Kill, Staten Island, NY
NYISO
 
100.0
 
858

 
Natural Gas
Astoria Gas Turbines, Queens, NY
NYISO
 
100.0
 
508

 
Natural Gas
Aurora, IL
PJM
 
100.0
 
878

 
Natural Gas
Avon Lake, OH (e)
PJM
 
100.0
 
732

 
Coal
Avon Lake, OH
PJM
 
100.0
 
21

 
Oil
Blossburg, PA
PJM
 
100.0
 
19

 
Natural Gas
Bowline, West Haverstraw, NY
NYISO
 
100.0
 
758

 
Natural Gas
Brunot Island, Pittsburgh, PA
PJM
 
100.0
 
259

 
Natural Gas
Canal, Sandwich, MA
ISO-NE
 
100.0
 
1,112

 
Oil
Chalk Point, Aquasco, MD (i)
PJM
 
100.0
 
667

 
Coal
Chalk Point, Aquasco, MD
PJM
 
100.0
 
1,690

 
Natural Gas
Cheswick, Springdale, PA
PJM
 
100.0
 
565

 
Coal
Conemaugh, New Florence, PA
PJM
 
20.2
(a) 
343

 
Coal
Conemaugh, New Florence, PA
PJM
 
20.2
(a) 
2

 
Oil
Connecticut Jet Power, CT (four sites)
ISO-NE
 
100.0
 
142

 
Oil
Devon, Milford, CT
ISO-NE
 
100.0
 
133

 
Oil
Dickerson, MD (i)
PJM
 
100.0
(b) 
537

 
Coal
Dickerson, MD
PJM
 
100.0
(b) 
312

 
Natural Gas
Dunkirk, NY (e)
NYISO
 
100.0
 
75

 
Coal
Fisk, Chicago, IL
PJM
 
100.0
 
197

 
Oil
Gilbert, Milford, NJ (j)
PJM
 
100.0
 
536

 
Natural Gas

50

                                                                                     

Glen Gardner, NJ (j)
PJM
 
100.0
 
160

 
Natural Gas
Hamilton, East Berlin, PA
PJM
 
100.0
 
20

 
Oil
Hunterstown CCGT, Gettysburg, PA
PJM
 
100.0
 
810

 
Natural Gas
Hunterstown CTS, Gettysburg, PA
PJM
 
100.0
 
60

 
Natural Gas
Huntley, Tonawanda, NY
NYISO
 
100.0
 
380

 
Coal
Indian River, Millsboro, DE 
PJM
 
100.0
 
410

 
Coal
Indian River, Millsboro, DE 
PJM
 
100.0
 
16

 
Oil
Joliet, I