10-K 1 nrg201610-k.htm 10-K Document

 
 
 
 
 
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, 2016.
 
 
 
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.)
 
 
 
804 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 $4,180,823,320 based on the closing sale price of $14.99 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, 2017
Common Stock, par value $0.01 per share
 
315,972,715
Documents Incorporated by Reference:
Portions of the Registrant's definitive Proxy Statement relating to its 2017 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:
2016 Revolving Credit Facility
 
The Company's $2.5 billion revolving credit facility, a component of the 2016 Senior Credit Facility. The revolving credit facility consists of $289 million of Tranche A Revolving Credit Facility, due 2018, and $2.2 billion of Tranche B Revolving Credit Facility, due 2021
2016 Senior Credit Facility
 
NRG's senior secured credit facility, comprised of the 2016 Revolving Credit Facility and the 2023 Term Loan Facility
2023 Term Loan Facility
 
The Company's $1.9 billion term loan facility due 2023, a component of the 2016 Senior Credit Facility
AEP
 
American Electric Power
Alta Wind Assets
 
Seven wind facilities that total 947 MW located in Tehachapi, California and a portfolio of land leases
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 GAAP
ASU
 
Accounting Standards Updates – updates to the ASC
Average realized prices
 
Volume-weighted average power prices, net of average fuel costs and reflecting the impact of settled hedges
AZNMSNV
 
Arizona, New Mexico and Southern Nevada
Backlog
 
Projects that are under construction, contracted, or awarded and represents a higher level of execution certainty
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
BRA
 
Base Residual Auction
BTU
 
British Thermal Unit
Buffalo Bear
 
Buffalo Bear, LLC, the operating subsidiary of Tapestry Wind LLC, which owns the Buffalo Bear project
Business Solutions
 
NRG's business solutions group, which includes demand response, commodity sales, energy efficiency and energy management services
CAA
 
Clean Air Act
CAIR
 
Clean Air Interstate Rule
CAISO
 
California Independent System Operator
CCF
 
Carbon Capture Facility
CCPI
 
Clean Coal Power Initiative
CDD
 
Cooling Degree Day
CDFW
 
California Department of Fish and Wildlife
CDWR
 
California Department of Water Resources
CEC
 
California Energy Commission
CenterPoint
 
CenterPoint Energy Houston Electric, LLC
CERT
 
Combustion Emissions Reduction Technologies, LLC
CFTC
 
U.S. Commodity Futures Trading Commission
C&I
 
Commercial, industrial and governmental/institutional
CES
 
Clean Energy Standard
CO2
 
Carbon Dioxide
CO2e
 
Carbon Dioxide Equivalents
COD
 
Commercial Operation Date

3


ComEd
 
Commonwealth Edison
Company
 
NRG Energy, Inc.
Consolidated Appropriations Act
 
Consolidated Appropriations Act of 2016
CPP
 
Clean Power Plan
CPS
 
Combined Pollutant Standard
CPUC
 
California Public Utilities Commission
CSAPR
 
Cross-State Air Pollution Rule
CVSR
 
California Valley Solar Ranch
CWA
 
Clean Water Act
D.C. Circuit
 
U.S. Court of Appeals for the District of Columbia Circuit
DGPV Holdco 1
 
NRG DGPV Holdco 1 LLC
DGPV Holdco 2
 
NRG DGPV Holdco 2 LLC
Direct Energy
 
Direct Energy Business Marketing, LLC
Distributed Solar
 
Solar power projects that primarily sell power to customers for usage on site, or are interconnected to sell power into a 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 of 2012
Dominion
 
Dominion Resources, Inc.
Drop Down Assets
 
Collectively, the June 2014 Drop Down Assets, the January 2015 Drop Down Assets, the November 2015 Drop Down Assets and the September 2016 Drop Down Assets
DSI
 
Dry Sorbent Injection
DSU
 
Deferred Stock Unit
Dunkirk Power
 
Dunkirk Power LLC
Economic gross margin
 
Sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales
EGU
 
Electric Utility Generating Unit
ELG
 
Effluent Limitations Guidelines
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
EMAAC
 
Eastern Mid-Atlantic Area Council
Energy Plus Holdings
 
Energy Plus Holdings LLC
EPA
 
U.S. Environmental Protection Agency
EPC
 
Engineering, Procurement and Construction
EPSA
 
The Electric Power Supply Association
ERCOT
 
Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
ERISA
 
The Employee Retirement Income Security Act of 1974
ESA
 
Energy Services Agreement
ESCO
 
Energy Service Company
ESP
 
Electrostatic Precipitator
ESPP
 
Amended and Restated 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

4


FERC
 
Federal Energy Regulatory Commission
FFB
 
Federal Financing Bank
FirstEnergy
 
FirstEnergy Corp.
FPA
 
Federal Power Act
FRCC
 
Florida Reliability Coordinating Council
Fresh Start
 
Reporting requirements as defined by ASC-852, Reorganizations
FTRs
 
Financial Transmission Rights
GAAP
 
Accounting principles generally accepted in the U.S.
GenConn
 
GenConn Energy LLC
GenOn
 
GenOn Energy, Inc.
GenOn Americas Generation
 
GenOn Americas Generation, LLC
GenOn Americas Generation Senior Notes
 
GenOn Americas Generation's $695 million outstanding unsecured senior notes consisting of $366 million of 8.5% senior notes due 2021 and $329 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 $1.8 billion outstanding unsecured senior notes consisting of $691 million of 7.875% senior notes due 2017, $649 million of 9.5% senior notes due 2018, and $490 million of 9.875% senior notes due 2020
GHG
 
Greenhouse Gas
Goal Zero
 
Goal Zero LLC
Green Mountain Energy
 
Green Mountain Energy Company
GWh
 
Gigawatt Hour
HAP
 
Hazardous Air Pollutant
HDD
 
Heating Degree Day
Heat Rate
 
A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWhs 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
HLBV
 
Hypothetical Liquidation at Book Value
HLM
 
High Lonesome Mesa, LLC
IASB
 
Independent Accounting Standards Board
ICAP
 
New York Installed Capacity
ICE
 
Intercontinental Exchange
IFRS
 
International Financial Reporting Standards
ILU
 
Illinois Union Insurance Company
IPA
 
Illinois Power Authority
IPPNY
 
Independent Power Producers of New York
ISO
 
Independent System Operator, also referred to as RTOs
ISO-NE
 
ISO New England Inc.
ITC
 
Investment Tax Credit
January 2015 Drop Down Assets
 
The Laredo Ridge, Tapestry and Walnut Creek projects, which were sold to NRG Yield, Inc. on January 2, 2015
June 2014 Drop Down Assets
 
The High Desert, Kansas South and El Segundo Energy Center projects, which were sold to NRG Yield, Inc. on June 30, 2014
JX Nippon
 
JX Nippon Oil Exploration (EOR) Limited
Kansas South
 
NRG Solar Kansas South LLC, the operating subsidiary of NRG Solar Kansas South Holdings LLC, which owns the RE Kansas South project

5


KPPH
 
1,000 Pounds Per Hour
kV
 
Kilovolts
kWh
 
Kilowatt-hour
LA DEQ
 
Louisiana Department of Environmental Quality
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
LSE
 
Load Serving Entities
LTIPs
 
Collectively, the NRG Long-Term Incentive Plan, as amended, and the NRG GenOn Long-Term Incentive Plan
MAAC
 
Mid-Atlantic Area Council
Marsh Landing
 
NRG Marsh Landing, LLC (formerly known as GenOn Marsh Landing, LLC)
Mass Market
 
Residential and small commercial customers
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
Midwest Generation
 
Midwest Generation, LLC
MISO
 
Midcontinent Independent System Operator, Inc.
MMBtu
 
Million British Thermal Units
MOPR
 
Minimum Offer Price Rule
MSU
 
Market Stock Unit
MW
 
Megawatts
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
NEPOOL
 
New England Power Pool
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.
NextEra
 
NextEra Energy Resources, LLC
NJDEP
 
New Jersey Department of Environmental Protection
NOL
 
Net Operating Loss
NOV
 
Notice of Violation
November 2015 Drop Down Assets
 
75% of the Class B interests of NRG Wind TE Holdco, which owns a portfolio of 12 wind facilities totaling 814 net MW
NOx
 
Nitrogen Oxides
NPDES
 
National Pollutant Discharge Elimination System
NPNS
 
Normal Purchase Normal Sale

6


NQSO
 
Non-Qualified Stock Option
NRC
 
U.S. Nuclear Regulatory Commission
NRG
 
NRG Energy, Inc.
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, as amended
NRG Wind TE Holdco
 
NRG Wind TE Holdco LLC
NRG Yield
 
Reporting segment including the projects owned by NRG Yield, Inc.
NRG Yield 2019 Convertible Notes
 
$345 million aggregate principal amount of 3.50% Convertible Senior Notes due 2019 issued by NRG Yield, Inc.
NRG Yield 2020 Convertible Notes
 
$287.5 million aggregate principal amount of 3.25% Convertible Notes due 2020 issued by NRG Yield, Inc.
NRG Yield, Inc.
 
NRG Yield, Inc., the owner of 55.3% of the economic interests of NRG Yield LLC with a controlling interest, and issuer of publicly held shares of Class A and Class C common stock
NRG Yield Operating 2024 Senior Notes
 
NRG Yield Operating LLC's $500 million of 5.375% unsecured senior notes due 2024
NRG Yield Operating 2026 Senior Notes
 
NRGY Yield Operating LLC's $350 million of 5.00% unsecured senior notes due 2026
NRG Yield LLC
 
NRG Yield LLC, which owns, through its wholly owned subsidiary, NRG Yield Operating LLC, all of the assets set forth in the NRG Yield segment
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
Nuclear Waste Policy Act
 
U.S. Nuclear Waste Policy Act of 1982
NYAG
 
State of New York Office of Attorney General
NYISO
 
New York Independent System Operator
NYMEX
 
New York Mercantile Exchange
NYSERDA
 
New York State Energy Research and Development Authority
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
PER
 
Peak Energy Rate
PG&E
 
Pacific Gas and Electric Company
Pipeline
 
Projects that range from identified lead to shortlisted with an offtake, and represents a lower level of execution certainty
Pinnacle
 
Pinnacle Wind, LLC, the operating subsidiary of Tapestry Wind LLC, which owns the Pinnacle project
PJM
 
PJM Interconnection, LLC
PM
 
Particulate Matter
POJO
 
Powerton and Joliet, of which the Company leases 100% interests in Unit 7 and Unit 8 of the Joliet generating facility and the Powerton generating facility, through Midwest Generation
PPA
 
Power Purchase Agreement
PPTA
 
Power Purchase Tolling Agreement
PSD
 
Prevention of Significant Deterioration
PTC
 
Production Tax Credit
PUCN
 
Public Utilities Commission of Nevada
PUCO
 
Public Utility Commission of Ohio

7


PUCT
 
Public Utility Commission of Texas
PUHCA
 
Public Utility Holding Company Act of 2005
PURPA
 
Public Utility Regulatory Policies Act of 1978
QF
 
Qualifying Facility under PURPA
RAPA
 
Resource Adequacy Purchase Agreement
RCRA
 
Resource Conservation and Recovery Act of 1976
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
REMA
 
NRG REMA LLC, which in addition to its asset under ownership, leases a 100% interest in the Shawville generating facility and 16.7% and 16.5% interests in the Keystone and Conemaugh generating facilities, respectively
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
RESA
 
Retail Electric Supply Association
Retail
 
Reporting segment that includes NRG's residential and small commercial businesses which go to market as Reliant, NRG and other brands owned by NRG, as well as Business Solutions
Revolving Credit Facility
 
Prior to June 30, 2016, the Company's $2.5 billion revolving credit facility due 2018, a component of the Senior Credit Facility. On June 30, 2016, the Company replaced the Senior Credit Facility, including the Revolving Credit Facility, with the 2016 Senior Credit Facility
RFP
 
Request For Proposal
RGGI
 
Regional Greenhouse Gas Initiative
RMR
 
Reliability Must-Run
ROFO Agreement
 
Second Amended and Restated Right of First Offer Agreement by and between NRG Energy, Inc. and NRG Yield, Inc.
RPM
 
Reliability Pricing Model
RPS
 
Renewable Portfolio Standards
RPV Holdco
 
NRG RPV Holdco 1 LLC
RSSA
 
Reliability Support Service Agreement
RSU
 
Restricted Stock Unit
RTO
 
Regional Transmission Organization
Sabine
 
Sabine Cogen, L.P.
SACCWIS
 
Statewide Advisory Committee on Cooling Water Intake Structures
SCE
 
Southern California Edison Company
SCR
 
Selective Catalytic Reduction Control System
SDG&E
 
San Diego Gas & Electric
SEC
 
U.S. Securities and Exchange Commission
SECA
 
Seams Elimination Charge/Cost Adjustments/Assignments
Securities Act
 
The Securities Act of 1933, as amended
Senior Credit Facility
 
Prior to June 30, 2016, the Company's senior secured facility, comprised of the Term Loan Facility and the Revolving Credit Facility. On June 30, 2016, the Company replaced the Senior Credit Facility with the 2016 Senior Credit Facility
Senior Notes
 
NRG's $5.4 billion outstanding unsecured senior notes consisting of $398 million of 7.625% senior notes due 2018, $207 million of 7.875% senior notes due 2021, $992 million of 6.25% senior notes due 2022, $869 million of 6.625% senior notes due 2023 and $733 million of 6.25% senior notes due 2024, $1.0 billion of the 7.25% senior notes due 2026 and $1.25 billion of the 6.625% senior notes due 2027
SERC
 
Southeastern Electric Reliability Council
September 2016 Drop Down Assets
 
The CVSR Holdco interest, which was sold to NRG Yield, Inc. on September 1, 2016

8


Seward
 
The Seward Power Generating Station, a 525 MW coal-fired facility in Pennsylvania
SF6
 
Sulfur Hexafluoride
Shelby
 
The Shelby County Generating Station, a 352 MW natural gas-fired facility in Illinois
Sherwin
 
Sherwin Alumina Company
SIFMA
 
Securities Industry and Financial Markets Association
SNF
 
Spent Nuclear Fuel
SO2
 
Sulfur Dioxide
S&P
 
Standard & Poor's
SSR
 
System Support Resource
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
SunPower
 
SunPower Corporation, Systems
Taloga
 
Taloga Wind, LLC, the operating subsidiary of Tapestry Wind LLC, which owns the Taloga project
TCPA
 
Telephone Consumer Protection Act
Term Loan Facility
 
Prior to June 30, 2016, the Company's $2.0 billion term loan facility due 2018, a component of the Senior Credit Facility. On and after June 30, 2016, the 2023 Term Loan Facility, a component of the 2016 Senior Credit Facility
Texas Genco
 
Texas Genco LLC
Thermal Business
 
NRG Yield, Inc.’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
TOU
 
Time-of-use
TSA
 
Transportation Services Agreement
TSR
 
Total Shareholder Return
TVA
 
Tennessee Valley Authority
TWCC
 
Texas Westmoreland Coal Co.
TWh
 
Terawatt Hour
UNFCCC
 
United Nations Framework Convention on Climate Change
UPMC
 
University of Pittsburgh Medical Center
U.S.
 
United States of America
U.S. DOE
 
U.S. Department of Energy
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
VCP
 
Voluntary Clean-Up Program
VIE
 
Variable Interest Entity
Walnut Creek
 
NRG Walnut Creek, LLC, the operating subsidiary of WCEP Holdings, LLC, which owns the Walnut Creek project
WECC
 
Western Electricity Coordinating Council
Yield Operating
 
NRG Yield Operating LLC

9


PART I
Item 1 — Business
General
NRG Energy, Inc., or NRG or the Company, is a leading integrated power company built on the strength of the nation's largest and most diverse competitive electric generation portfolio and leading retail electricity platform. NRG aims to create a sustainable energy future by producing, selling and delivering electricity and related products and services in major competitive power markets in the U.S. in a manner that delivers value to all of NRG's stakeholders. The Company owns and operates approximately 47,000 MW of generation; engages in the trading of wholesale energy, capacity and related products; transacts in and trades fuel and transportation services; and directly sells energy, services, and innovative, sustainable products and services to retail customers under the names “NRG”, "Reliant" and other retail brand names owned by NRG. NRG was incorporated as a Delaware corporation on May 29, 1992.
Strategy
NRG's strategy is to maximize stockholder value through the safe production and sale of reliable and affordable power to its customers in the markets served by the Company, while positioning the Company to meet the market's increasing demand for sustainable, low carbon and customized energy solutions for the benefit of the end-use energy consumer. This strategy is intended to enable the Company to achieve 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.
To 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 alternative power generation technologies in its wholesale business, like wind and solar, and deploying innovative energy solutions for consumers within its retail businesses; 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.
Business Overview
The Company’s core businesses include wholesale conventional generation, retail electricity including personal power solutions and Business Solutions (included in the Retail segment, effective in January 2017), contracted generation owned by NRG Yield, Inc. (included in the NRG Yield segment) and renewable utility scale and distributed generation assets that are constructed or in development and that are not otherwise owned by NRG Yield, Inc. (included in the Renewables segment).
Generation
The Company’s wholesale power generation business includes the Company's wholesale operations including plant operations, commercial operations, EPC, energy services and other critical related functions. In addition to the traditional functions, the wholesale power generation business also includes NRG’s conventional distributed generation business, consisting of reliability, combined heat and power and large-scale distributed generation.
The wholesale generation 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. The Company has one of the largest and most diversified power generation portfolios in the U.S., with approximately 42,000 MW of fossil fuel and nuclear generation capacity at 85 plants as of December 31, 2016. 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 significant upside potential that can arise during periods of high demand, which typically drive higher energy prices. As of December 31, 2016, less than 25% of the Company's consolidated operating revenues were derived from coal-fired operating assets.

10


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 the Company 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 the Company's generation assets, however, are located within densely populated areas that tend to have higher wholesale pricing as a result of relatively favorable local supply-demand balance. The Company 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, some 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. The Company believes that its extensive generation portfolio provides many asset optimization opportunities. During 2016, the Company completed gas conversion projects on facilities totaling more than 2,200 MW. The Company currently has over 1,000 MW targeted for Repowering initiatives, all of which are under development or construction.
In addition, the Company continuously evaluates opportunities for development of new generation, on both a merchant and contracted basis. As such, the majority of the Company's current developments are in response to RFPs for new generation and/or generating capacity backed by contracts with credit-worthy counterparties.  Many RFPs are issued by regulated utilities or electric system operators in response to reliability or renewable power mandates.  The Company competes against other power plant developers when responding to these RFPs.  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.
Retail
Retail provides energy and related services as well as personal power to Mass Market consumers through various brands and sales channels across the U.S. Retail also includes C&I customers and other distributed and reliability products which are within NRG's Business Solutions group. In 2016, Retail delivered approximately 42 TWhs and served approximately 2.8 million mass Recurring Customers. Retail's results make it the largest competitive Mass Market energy retailer in the U.S. and Texas, and one of the top six Mass Market energy retailers in the Eastern and Midwestern U.S. The majority of Retail's sales come in the competitive retail energy markets of Connecticut, Delaware, Illinois, Maryland, Massachusetts, New Jersey, New York, Ohio, Pennsylvania and Texas, as well as the District of Columbia.
Mass Market consumers make purchase decisions based on a variety of factors, including price, customer service, brand, product choices and value-added features. These consumers 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, Retail is able to attract, retain, and increase the value of its customer relationships. Retail's brands are recognized for exemplary customer service, innovative smart energy and technology product offerings and environmentally friendly solutions.
Included in Retail is the Company's Business Solutions group, which focuses on providing distributed products and services 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, the Company often benefits from its ability to supply energy products from its wholesale generation portfolio to commercial and industrial retail customers.
The Company also provides energy services including operations, maintenance, technical, development and asset management services to its own facilities and to external customers.









11


Renewables
The Company’s renewables business focuses on the acquisition, development and operation and maintenance of utility scale wind and solar, community solar and distributed solar generation assets as well as the management and operations of the renewable generation assets owned by NRG Yield, Inc. A substantial portion of the utility scale wind and solar generation facilities contained within the Company’s renewables business are subject to the ROFO Agreement between the Company and NRG Yield, Inc. In 2016, the Company acquired 1,637 MW of utility scale solar and wind projects and 107 MW of distributed generation and community solar projects that are currently under development or in operation across 12 states. The renewables business has in-house expertise that covers the full spectrum of development capabilities to execute on utility, distributed generation, and community solar projects. The asset management and operations and maintenance groups within the renewables business manage a portfolio of wind and solar assets across 26 states, serving as the primary commercial asset manager on the vast majority of assets owned by NRG and NRG Yield, Inc. In addition, the operations and maintenance groups self-perform plant operations on 2,675 MW on the consolidated fleet of assets owned by NRG and NRG Yield, Inc. and 224 MW on assets owned by third parties.
The utility wind and solar generation business targets strategic partnerships with utilities, municipalities and large national corporations for offsite wind and solar solutions. The distributed solar business targets partnerships with companies, municipalities, schools and communities to provide on-site and virtual net metering off-site renewable generation. The community solar business targets relationships with companies and municipalities as well as residential homeowners to provide off-site solar generation under community solar regulations and tariffs. In addition to assets in operation, as of December 31, 2016, the Company held a backlog of in-construction, contracted and awarded projects of 543 MW, and a pipeline of 3,268 MW across the utility and distributed solar renewables markets.
Similar to the wholesale business, the renewables business also competes for new generation opportunities through both RFPs and bilateral solicitations. The renewables business selects markets and projects to compete based on resource relative to the value of the power, while seeking to make use of NRG capabilities in a competitive landscape. The number and type of competitors vary based on location, generation type, project size and counterparty.  The renewables business competes with traditional utilities as well as companies that provide products and services in the downstream solar and wind energy value chains.
NRG Yield
NRG Yield, Inc. is a publicly-traded, dividend growth-oriented company formed to serve as the primary vehicle through which NRG owns, operates and acquires diversified contracted renewable and conventional generation and thermal infrastructure assets. As of December 31, 2016, NRG owns a 55.1% voting interest in the outstanding common stock of NRG Yield, Inc. NRG Yield, Inc.’s contracted generation portfolio collectively represents 4,563 net MW as of December 31, 2016. 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 1,319 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 directly benefits 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 ROFO Agreement. The proceeds of such future sales are expected to provide the Company with a portion of the capital utilized under its capital allocation program. 

12


GenOn Liquidity
As disclosed in Item 15 - Note 1, Nature of Business, and Note 12, Debt and Capital Leases, to the Consolidated Financial Statements, $691 million of GenOn's Senior Notes, excluding $8 million of associated premiums, are current within the GenOn consolidated balance sheet as of December 31, 2016 and are due on June 15, 2017. GenOn's future profitability continues to be adversely affected by (i) a sustained decline in natural gas prices and its resulting effect on wholesale power prices and capacity prices, and (ii) the inability of GenOn Mid-Atlantic and REMA to make distributions of cash and certain other restricted payments to GenOn. Based on current projections, GenOn is not expected to have sufficient liquidity to repay the Senior Notes due in June 2017. As a result of these factors, there is substantial doubt about GenOn's ability to continue as a going concern. As a result of the substantial doubt about GenOn’s ability to continue as a going concern, along with additional factors, there is substantial doubt about certain of GenOn’s subsidiaries’ ability to continue as a going concern.
The Company, GenOn's parent company, has no obligation to provide any financial support to GenOn other than under the secured intercompany revolving credit agreement between the Company and GenOn and NRG Americas. As of December 31, 2016, $228 million was available to be used by GenOn under the $500 million revolving credit agreement. As controlled group members, ERISA requires that NRG and GenOn are jointly and severally liable for the NRG Pension Plan for Bargained Employees and the NRG Pension Plan, including the pension liabilities associated with GenOn employees.
GenOn is currently considering all options available to it, including negotiations with creditors, refinancing the GenOn Senior Notes, potential sales of certain generating assets as well as the possibility for a need to file for protection under Chapter 11 of the U.S. Bankruptcy Code. During 2016, GenOn appointed two independent directors, retained advisors and established a separate audit committee as part of this process. Any resolution may have a material impact on the Company's statement of operations, cash flows and financial position.

As of December 31, 2016, GenOn represents 15.6% of the Company's consolidated total assets, 16.9% of the Company's consolidated total liabilities and contributed $94 million to the Company's consolidated cash from operations in 2016.

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, 2016, as well as customer, load and regional information surrounding the operation of NRG’s retail businesses:

13


    ainfo.jpg

14


The following table summarizes NRG's global generation portfolio as of December 31, 2016:
 
 
Global Generation Portfolio(a)
 
 
(In MW)
 
 
Generation
 
 
 
 
 
 
 
 
Generation Type
 
Gulf Coast
 
East
 
West
 
Other
 
Renewables (b)
 
NRG Yield (c)
 
Corporate(d)
 
Total Global
Natural gas(e)
 
8,635

 
8,444

 
6,085

 
144

 

 
1,878

 

 
25,186

Coal(f)
 
5,114

 
7,465

 

 
605

 

 

 

 
13,184

Oil(g)
 

 
5,477

 

 

 

 
190

 

 
5,667

Nuclear
 
1,136

 

 

 

 

 

 

 
1,136

Wind
 

 

 

 

 
961

 
2,005

 

 
2,966

Utility Scale Solar
 

 

 

 

 
987

 
610

 

 
1,597

Distributed Solar
 

 

 

 

 
105

 
9

 
114

 
228

Total generation capacity(h)
 
14,885

 
21,386

 
6,085

 
749

 
2,053

 
4,692

 
114

 
49,964

Capacity attributable to noncontrolling interest(h)
 

 

 

 

 
(638
)
 
(2,110
)
 

 
(2,748
)
Total net generation capacity
 
14,885

 
21,386

 
6,085

 
749

 
1,415

 
2,582

 
114

 
47,216

(a) All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.
(b) Includes Distributed Solar capacity from assets held by DGPV Holdco 1 and DGPV Holdco 2. Excludes 100 MW related to the High Lonesome Mesa facility, which was transferred to lien holders on March 31, 2016.
(c) Does not include NRG Yield, Inc.'s thermal converted (MWt) capacity, which is part of the NRG Yield operating segment.
(d) The Distributed Solar figure within "Corporate" includes the aggregate production capacity of installed and activated residential solar energy systems. Also includes capacity from operating portfolios of residential solar assets held by RPV Holdco.
(e) New Castle Units 3, 4, and 5 and Joliet Units 6, 7, and 8, totaling 1,651 MW, were moved to natural gas from coal following the completion of natural gas addition and conversion projects, respectively, in the second quarter of 2016. Natural gas generation portfolio does not include 878 MW related to Aurora and 450 MW related to Rockford, which were both sold on July 12, 2016. Natural gas generation portfolio includes 597 MW related to Shawville which completed a natural gas addition in the second quarter of 2016 and 275 MW related to Choctaw Unit 1 which is in forced outage and expected to return to service in December 2017.
(f) Coal generation portfolio does not include 94 MW related to Avon Lake 7, which was deactivated in April 2016. New Castle Units 3, 4, and 5 and Joliet Units 6, 7, and 8, totaling 1,651 MW were moved from coal -to natural gas following completion of natural gas addition and conversion projects, respectively, in the second quarter of 2016. Does not include 597 MW related to Shawville which completed a natural gas addition project in the second quarter of 2016. Coal generation portfolio does not include 525 MW related to the Seward generating facility and 380 MW related to the Huntley generating facility, which were sold and deactivated in the first quarter of 2016, respectively.
(g) Oil generation portfolio does not include 104 MW related to the Astoria Oil Turbines which were deactivated in the first quarter of 2016.
(h) NRG Yield's total generation capacity includes 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's total generation capacity net of this noncontrolling interest was 4,686 MWs.

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 2021. Over a third 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 extending through various dates in 2025, which largely hedges a portion of the Company's generation in this region. In addition, as of December 31, 2016, the Company had purchased fuel forward under fixed price contracts, with contractually-specified price escalators, for approximately 30% of its expected coal requirement from 2017 to 2021. 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.

15


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 typically have durations from 10 years to as much as 25 years.
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 and related commodity and financial products, including forwards, futures, options and swaps, through its ownership of BETM, which is also an energy management service provider for primarily third-party generating assets. Certain other NRG entities trade to a lesser extent, utilizing similar products as well as oil and weather products. The Company 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, 2016 and through 2020 for the Company's Gulf Coast region:
Gulf Coast
 
2017
 
2018
 
2019
 
2020
 
Annual
Average for
2017-2020
 
 
(Dollars in millions unless otherwise stated)
Net Coal and Nuclear Capacity (MW) (a)
 
6,250

 
6,250

 
6,250

 
6,250

 
6,250

Forecasted Coal and Nuclear Capacity (MW) (b)
 
4,959

 
4,411

 
4,119

 
4,198

 
4,422

Total Coal and Nuclear Sales (GWh) (c)
 
39,002

 
19,624

 
8,471

 
7,653

 
18,687

Percentage Coal and Nuclear Capacity Sold Forward (d)
 
90
%
 
51
%
 
23
%
 
21
%
 
46
%
Total Forward Hedged Revenues (e)
 
$
1,429

 
$
747

 
$
429

 
$
406

 
$

Weighted Average Hedged Price ($ per MWh) (e)
 
$
36.63

 
$
38.07

 
$
50.68

 
$
53.07

 
$

Average Equivalent Natural Gas Price ($ per MMBtu) (e)
 
$
3.68

 
$
3.91

 
$
4.83

 
$
4.99

 
$

Gross Margin Sensitivities
 
 
 
 
 
 
 
 
 
 
Gas Price Sensitivity Up $0.50/MMBtu on Coal and Nuclear Units
 
$
1

 
$
76

 
$
124

 
$
147

 
$

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

 
$
(69
)
 
$
(113
)
 
$
(124
)
 
$

Heat Rate Sensitivity Up 1 MMBtu/MWh on Coal and Nuclear Units
 
$
53

 
$
100

 
$
91

 
$
96

 
$

Heat Rate Sensitivity Down 1 MMBtu/MWh on Coal and Nuclear Units
 
$
(36
)
 
$
(79
)
 
$
(71
)
 
$
(77
)
 
$

(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, 2016, 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 GWh based on forward market implied heat rate as of December 31, 2016, and then combined with power sales to arrive at equivalent GWh 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.

16


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, 2016 and through 2020 for the East region:
East
 
2017
 
2018
 
2019
 
2020
 
Annual
Average for
2017-2020
 
 
(Dollars in millions unless otherwise stated)
Net Coal Capacity (MW) (a)
 
7,465

 
7,465

 
7,465

 
7,167

 
7,391

Forecasted Coal Capacity (MW) (b)
 
3,688

 
3,200

 
2,483

 
2,141

 
2,878

Total Coal Sales (GWh) (c)
 
31,905

 
5,265

 
455

 
81

 
9,427

Percentage Coal Capacity Sold Forward (d)
 
99
%
 
19
%
 
2
%
 
%
 
30
%
Total Forward Hedged Revenues (e)
 
$
1,162

 
$
175

 
$
16

 
$
2

 
$

Weighted Average Hedged Price ($ per MWh) (e)
 
$
36.41

 
$
33.27

 
$

 
$

 
$

Average Equivalent Natural Gas Price ($ per MMBtu) (e)
 
$
3.69

 
$
3.29

 
$

 
$

 
$

Gross Margin Sensitivities
 
 
 
 
 
 
 
 
 
 
Gas Price Sensitivity Up $0.50/MMBtu on Coal Units
 
$
64

 
$
206

 
$
230

 
$
215

 
$

Gas Price Sensitivity Down $0.50/MMBtu on Coal Units
 
$
(35
)
 
$
(162
)
 
$
(159
)
 
$
(140
)
 
$

Heat Rate Sensitivity Up 1 MMBtu/MWh on Coal Units
 
$
64

 
$
119

 
$
121

 
$
110

 
$

Heat Rate Sensitivity Down 1 MMBtu/MWh on Coal Units
 
$
(35
)
 
$
(99
)
 
$
(95
)
 
$
(86
)
 
$

(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, 2016, 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 GWh based on forward market implied heat rate as of December 31, 2016, and then combined with power sales to arrive at equivalent GWh 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.
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:
Capacity auctions — The Company's largest sources of capacity revenues are capacity auctions in PJM, ISO-NE, and NYISO. Both ISO-NE and PJM operate a pay-for-performance model where capacity payments are modified based on real-time performance, where NRG's actual revenues will be the combination of revenues based on the cleared auction MWs plus the net of any over- and under-performance of NRG's fleet. In addition, MISO has 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.  Recent changes have made the decision to import external capacity into the PJM market more complicated, and the Company is evaluating the feasibility of continuing to import.
Resource Adequacy and bilateral contracts — In California, there is a 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 nine Louisiana distribution cooperatives, which expire in 2025. NRG also had full requirements contracts in PJM in 2016.  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. In Texas, capacity and contracted revenues are through bilateral contracts with load serving entities.
Long-term PPAs — Output from the majority of renewable energy assets and certain conventional energy plants is sold through long-term PPAs and tolling agreements to a single counterparty, which is often a utility or commercial customer.


17


Fuel Supply and Transportation
NRG's fuel requirements consist of various forms of fossil fuel (including coal, natural gas and oil) and nuclear fuel. The prices of fossil fuels are highly volatile. The Company obtains its fossil fuels from multiple suppliers and through multiple transporters. 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 2017. NRG actively manages its coal requirements based on forecasted generation, market volatility and its inventory on site. As of December 31, 2016, NRG had purchased forward contracts to provide fuel for approximately 27% of the Company's expected requirements from 2017 through 2021, including expected coal inventory draw down. NRG purchased approximately 25 million tons of coal in 2016, of which 84% was Powder River Basin coal and lignite. For fuel transport, NRG has entered into various rail and barge transportation and rail car lease agreements with varying tenures that provide for most of the Company's transportation requirements of Powder River Basin coal for the next 5 years and for all of the Company's transportation requirements of Appalachian and Colorado coal for the next two years.
The following table shows the percentage of the Company's coal requirements from 2017 through 2021 that have been purchased forward as of December 31, 2016:
 
Percentage of
Company's
Requirement (a)
2017
95
%
2018
41
%
2019
%
2020
%
2021
%
(a)
Includes expected coal inventory draw down.
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 these types of 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.
Retail Operations
In 2016, NRG's retail businesses 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 2016, NRG's retail businesses sold approximately 61 TWhs of electricity. In any given year, the quantity of TWhs 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.

18


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.
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, 2016 and 2015:
 
Year Ended December 31, 2016
 
 
 
 
 
Fossil and Nuclear Plants
 
Net Owned
Capacity (MW)
 
Net Generation (MWh) (In thousands)
 
Annual Equivalent Availability Factor
 
Average Net Heat Rate BTU/kWh
 
Net Capacity
Factor
 
 
 
 
 
 
 
 
 
 
Generation
 
 
 
 
 
 
 
 
 
Gulf Coast
14,879

 
51,100

 
86.9
%
 
9,846

 
39.2
%
East
21,386

 
35,423

 
79.5

 
10,397

 
18.4

West
6,085

 
4,369

 
88.7

 
8,292

 
8.3

Renewables
2,053

 
3,883

 
96.8

 

 
40.1

NRG Yield (a)
4,692

 
11,174

 
97.9

 
8,859

 
25.5

 
Year Ended December 31, 2015
 
 
 
 
 
Fossil and Nuclear Plants
 
Net Owned
Capacity (MW)
 
Net Generation (MWh) (In thousands)
 
Annual Equivalent Availability Factor
 
Average Net Heat Rate BTU/kWh
 
Net Capacity
Factor
 
 
Generation
 
 
 
 
 
 
 
 
 
Gulf Coast
14,941

 
57,678

 
85.7
%
 
9,651

 
44.4
%
East
23,579

 
46,286

 
84.0

 
10,477

 
21.6

West
6,085

 
4,542

 
86.4

 
9,189

 
8.1

Renewables
1,966

 
3,790

 
95.0

 

 
39.4

NRG Yield (a)
4,565

 
11,142

 
95.7

 
8,651

 
22.9

(a)
NRG Yield includes thermal generation.

19


The generation performance by region for the three years ended December 31, 2016, 2015, and 2014, is shown below:
 
Net Generation
 
2016
 
2015
 
2014
 
(In thousands of MWh)
Generation
 
 
 
 
 
Gulf Coast
 
 
 
 
 
Coal
24,620

 
29,301

 
36,794

Gas
16,921

 
19,804

 
13,967

Nuclear (a)
9,559

 
8,573

 
9,111

Total Gulf Coast
51,100

 
57,678

 
59,872

East
 
 
 
 
 
Coal
24,614

 
36,245

 
42,939

Oil
1,432

 
1,583

 
1,269

Gas
9,377

 
8,458

 
6,983

Total East
35,423

 
46,286

 
51,191

West
 
 
 
 
 
Gas
4,369

 
4,542

 
4,241

Total West
4,369

 
4,542

 
4,241

Renewables
 
 
 
 
 
Solar
1,690

 
1,509

 
1,220

Wind
2,193

 
2,281

 
2,125

Total Renewables
3,883

 
3,790

 
3,345

NRG Yield
 
 
 
 
 
Solar
1,226

 
1,212

 
1,250

Wind
6,010

 
5,199

 
3,427

Gas and Dual-Fuel
3,938

 
4,731

 
4,396

Total NRG Yield (b)
11,174

 
11,142

 
9,073

(a)
MWh information reflects the Company's undivided interest in total MWh generated by STP.
(b)
Total NRG Yield includes thermal heating and chilled water generation.

20


Segment Review
The Company's segment structure reflects how management currently makes financial decisions and allocates resources. During January 2017, the Company's businesses are segregated as follows: Generation (previously named Generation/Business), which includes generation, international and BETM (previously part of Corporate); Retail (previously named Retail Mass) which includes Mass customers (previously NRG Home Retail), and Business Solutions, which includes C&I customers and other distributed and reliability products (previously in the Generation segment); Renewables (previously named NRG Renew), which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and corporate activities. The Company's corporate segment include residential solar (previously part of NRG Home) and electric vehicle services. During 2016, the Company began reporting the results of its residential solar business in its corporate segment and its international business in its Generation segment. Intersegment sales are accounted for at market. The Company has recast data from prior periods to reflect changes in reportable segments to conform to the current year presentation. NRG Yield includes certain of the Company's contracted generation assets. On September 1, 2016, NRG Yield acquired the remaining 51.05% interest in CVSR Holdco LLC, which indirectly owns the CVSR solar facility, from the Company. This acquisition was accounted for as transfers of entities under common control and accordingly, 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, 2016, 2015 and 2014, 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, to the consolidated financial statements for information about facilities in each of NRG's business segments.
 
Year Ended December 31, 2016
 
Energy
Revenues
 
Capacity
Revenues
 
Retail
Revenues
 
Mark-to-
Market
Activities
 
Contract Amortization
 
Other
Revenues(a)
 
Total
Operating
Revenues(b)
 
(In millions)
Generation
$
4,506

 
$
1,565

 
$

 
$
(787
)
 
$
15

 
$
380

 
$
5,679

Retail
2

 
82

 
6,239

 
(1
)
 
(1
)
 
15

 
6,336

Renewables
375

 

 

 
(6
)
 
(1
)
 
49

 
417

NRG Yield
575

 
345

 

 

 
(68
)
 
169

 
1,021

Corporate and Eliminations (b)
(989
)
 
(22
)
 
35

 
(71
)
 

 
(55
)
 
(1,102
)
Total
$
4,469

 
$
1,970

 
$
6,274

 
$
(865
)
 
$
(55
)
 
$
558

 
$
12,351

(a)
Primarily consists of revenues generated by the Thermal business (NRG Yield segment), operation and maintenance revenues and unrealized trading activities, primarily at BETM (Generation segment).
(b)
Energy revenues include inter-segment sales primarily between Generation and Retail.
 
Year Ended December 31, 2015
 
Energy
Revenues
 
Capacity
Revenues
 
Retail
Revenues
 
Mark-to-
Market
Activities
 
Contract Amortization
 
Other
Revenues(c)
 
Total
Operating
Revenues(d)
 
(In millions)
Generation
$
5,716

 
$
1,831

 
$

 
$
(254
)
 
$
15

 
$
238

 
$
7,546

Retail

 
116

 
6,778

 
4

 

 
16

 
6,914

Renewables
359

 

 

 
(3
)
 
(1
)
 
37

 
392

NRG Yield
489

 
341

 

 
(2
)
 
(54
)
 
179

 
953

Corporate and Eliminations (d)
(1,070
)
 
(14
)
 
28

 
11

 

 
(86
)
 
(1,131
)
Total
$
5,494

 
$
2,274

 
$
6,806

 
$
(244
)
 
$
(40
)
 
$
384

 
$
14,674

(c)
Primarily consists of revenues generated by the Thermal business (NRG Yield segment), operation and maintenance revenues and unrealized trading activities, primarily at BETM (Generation segment).
(d)
Energy revenues include inter-segment sales primarily between Generation and Retail.



21


 
Year Ended December 31, 2014
 
Energy
Revenues
 
Capacity
Revenues
 
Retail
Revenues(f)
 
Mark-to-
Market
Activities
 
Contract Amortization
 
Other
Revenues(e)
 
Total
Operating
Revenues(f)
 
(In millions)
Generation
$
6,601

 
$
1,786

 
$

 
$
535

 
$
16

 
$
350

 
$
9,288

Retail

 
1

 
7,372

 

 
1

 
19

 
7,393

Renewables
302

 
1

 

 
4

 
(1
)
 
38

 
344

NRG Yield
352

 
321

 

 
2

 
(29
)
 
182

 
828

Corporate and Eliminations(f)
(1,833
)
 
(22
)
 
4

 
(40
)
 

 
(94
)
 
(1,985
)
Total
$
5,422

 
$
2,087

 
$
7,376

 
$
501

 
$
(13
)
 
$
495

 
$
15,868

(e)
Primarily consists of revenues generated by the Thermal business (NRG Yield segment), operation and maintenance revenues and unrealized trading activities, primarily at BETM (Generation segment).
(f)
Energy revenues include inter-segment sales primarily between Generation and Retail.
Seasonality and Price Volatility
Annual and quarterly operating results of the Company's wholesale power generation segments can be significantly affected by weather, including wind resource availability, 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. 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.
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.  ERCOT is an energy only market, and has implemented market rule changes to provide pricing more reflective of higher energy value when operating reserves are scarce or constrained.  NRG also operates generation assets that are principally located within 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 requirements service to LSEs, including cooperatives and municipalities in the MISO region.


22


East
NRG's generation and demand response assets located in the East region of the U.S. are within the control areas of ISO-NE, NYISO 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, the East region receives a significant portion of its revenues from capacity markets in ISO-NE, NYISO and PJM. PJM and ISO-NE use a three-year forward capacity auction construct, while NYISO uses a month-ahead capacity auction construct. Capacity market prices are sensitive to design parameters, as well as additions of new capacity. Both ISO-NE and PJM operate a pay-for-performance model where capacity payments are modified based on real-time generator performance. In such markets, NRG’s actual revenues will be the combination of cleared auction prices times the quantity of MWs cleared, plus the net of any over-performance “bonus payments” and any under-performance charges. In both markets, bidding rules allow for the incorporation of a risk premium into generator bids.
West
NRG 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, ancillary services and capacity products at market-based rates, either within the CAISO's centralized energy and ancillary service markets or bilaterally pursuant to tolling arrangements or other capacity sales with California's LSEs. The CPUC also determines capacity requirements for LSEs and 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 areas. Additionally, the CAISO has independent authority to contract with needed resources under certain circumstances, typically either when LSEs have failed to procure sufficient resources, or system conditions change unexpectedly. NRG is also pursuing Repowering projects at several southern California sites pursuant to long-term contracts.
Renewables
NRG operates a fleet of utility scale and distributed renewable generating assets across the U.S. Many states have implemented their own renewable portfolio standards requiring LSEs to provide a given percentage of their energy sales from renewable resources. As a result, a number of LSEs have entered into long-term PPAs with the NRG's utility scale renewable generating facilities. There are examples of states increasing their RPS from initially stated levels, such as California’s recently enacted 50% RPS by 2030 and Hawaii’s goal of achieving 100% renewables by 2045. In addition, given the cost competitiveness of renewables, LSEs are procuring renewables in excess of their RPS obligations. In December 2015, the U.S. Congress extended the 30% solar ITC so that projects which begin construction in 2016 through 2019 will continue to qualify for the 30% ITC.  Projects beginning construction in 2020 and 2021 will be eligible for the ITC at the rates of 26% and 22%, respectively.  The same legislation also extended the 10-year wind PTC for wind projects which begin construction in years 2016 through 2019.  Wind projects which begin construction in the years 2017, 2018 and 2019 are eligible for PTC at 80%, 60% and 40% of the statutory rate per kWh, respectively.
Retail
NRG's retail businesses sell 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's retail businesses competitively offer 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. In Texas, NRG’s retail business activities 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. A majority of the retail 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. 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's retail offerings in each state may be impacted by the rules, regulations, market structure and communication requirements from public utility commissions across the country.

23


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 NERC and the regional reliability entities in the regions where NRG 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 NRG's ownership interest in STP.
Federal Regulation
CFTC
The CFTC, among other things, regulates the trading of swaps, futures and many commodities under the Commodity Exchange Act, or CEA. Since 2010, there have been a number of reforms to the regulation of the derivatives markets, both in the U.S. and internationally. These regulations, and any further changes thereto, or adoption of additional regulations, including any regulations relating to position limits on futures and other derivatives or margin for derivatives, could negatively impact NRG’s ability to hedge its portfolio in an efficient, cost-effective manner by, among other things, potentially decreasing liquidity in the forward commodity and derivatives markets or limiting NRG’s ability to utilize non-cash collateral for derivatives transactions.
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.
Current Administration and Changeover at FERC — FERC is currently without a quorum and cannot issue orders in contested proceedings until a new Commissioner is appointed. FERC’s day-to-day work can continue through authority that has been delegated to FERC Staff. With a new administration and three vacant positions at FERC, NRG’s business may be affected because its generation fleet is subject to changes in FERC regulatory policy.

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 NRG's ownership interest in STP.
In New York, NRG'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 NRG's generation assets located in New York. NRG 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, NRG'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 depends on state competition and other policies.

24


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 1997 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. See also Item 15 — Note 6, Nuclear Decommissioning Trust Fund, to the Consolidated Financial Statements for additional discussion.
In the event that the funds from the trusts are ultimately determined to be inadequate to decommission the STP facilities, the original owners of the Company's STP interests, CenterPoint and AEP, each will be required to collect, through their PUCT-authorized non-bypassable rates or other charges to customers, additional amounts required to fund NRG 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.
STP License Amendment — STP Unit 1 was operating with a single-cycle license amendment issued on December 11, 2015 after a control rod was determined to be inoperable following a scheduled refueling and maintenance outage. The approved license amendment to support STP Unit 1 operation with the inoperable control rod and the associated control rod drive shaft removed was granted by the NRC on December 21, 2016.

25


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
2019/2020 PJM Auction Results — On May 24, 2016, PJM announced the results of its 2019/2020 base residual auction. NRG cleared approximately 11,155 MW of Capacity Performance product and 371 MW of Base Capacity product in the 2019/2020 base residual auction. NRG’s expected capacity revenues from the base residual auction for the 2019/2020 delivery year are approximately $569 million.
The table below provides a detailed description of NRG’s 2019/2020 base residual auction results from May 24, 2016:
 
 
Base Capacity Product
 
Capacity Performance Product
Zone
 
Cleared Capacity (MW)(a)(b)
 
Price
($/MW-day)
 
Cleared Capacity (MW)(a)(b)
 
Price
($/MW-day)
COMED
 
65
 
$
182.77

 
3,738
 
$
202.77

EMAAC
 
103
 
$
99.77

 
895
 
$
119.77

MAAC
 
10
 
$
80.00

 
5,972
 
$
100.00

RTO
 
193
 
$
80.00

 
550
 
$
100.00

Total
 
371
 
 
 
11,155
 
 
(a) Includes imports. Does not include capacity sold by NRG Curtailment Specialists. Excludes cleared capacity related to Aurora and Rockford, the sales of which were completed on July 12, 2016.
(b) Includes GenOn.

PJM Capacity Performance Appeals — On or about July 8, 2016, four petitions were filed at the D.C. Circuit seeking review of the FERC orders approving PJM’s Capacity Performance revisions to its forward capacity market after motions for rehearing at FERC were denied on May 10, 2016. NRG intervened in these matters on July 29, 2016. On December 9, 2016, NRG, along with other generators and industry trade groups, filed a joint brief in support of FERC's decision. Briefing is complete and oral argument occurred in February 2017. This case governs capacity revenues already received by NRG, as well as the revenues for forward periods.
PJM Seasonal Capacity Proceeding — On November 17, 2016, PJM proposed to enhance the ability of capacity storage resources, intermittent resources, demand response, energy efficiency, and environmentally limited resources, or collectively the seasonal capacity performance resources, to participate in the BRA and qualify as a resource providing the capacity performance product through aggregation. NRG filed comments specifically supporting PJM’s proposal to modify the aggregation rules to allow seasonal capacity resources to aggregate across LDAs and to allow aggregations through RPM auctions. On January 23, 2017, PJM amended its proposal to address questions from FERC. The outcome of this proceeding could have a material impact on future PJM capacity prices. 

Complaints Related to Extension of Base Capacity In 2015, FERC approved changes to PJM’s capacity market, which included moving from the Base Capacity product to the higher performance Capacity Performance product over the course of a five year transition. Under this transition, as of the May 2017 BRA, the Base Capacity product will no longer be available.  Several parties have filed complaints at FERC seeking to maintain the RPM Base Capacity product for at least one more delivery year or until such time as PJM develops a model for seasonal resources to participate. If the transition is delayed, capacity prices could be materially impacted. The matters are pending at FERC. 

MOPR Revisions — On May 2, 2013, FERC accepted PJM's proposal to substantially revise its Minimum Offer Price Rule, or MOPR.  Among other things, FERC approved the portions of the PJM proposal that exempt many new entrants from demonstrating that their proposed projects are economic, as well as providing a similar exemption for 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.  On June 3, 2013, NRG filed a request for rehearing of the FERC order and subsequently protested the manner in which PJM proposed to implement the FERC order. On October 15, 2015, FERC denied the requests for rehearing and accepted PJM’s compliance filing.  NRG, along with other parties, filed a petition for review of FERC's decision with the D.C. Circuit. Briefing is complete. The case is pending at the D.C. Circuit.

26



Illinois Zero Emission Credit Legislation and Related PJM Complaint Pursuant to legislation in Illinois, the Illinois Power Agency is to procure contracts for Zero Emission Credits, or ZECs, through a process that would take into account environmental benefits, including the preservation of zero emission facilities. The procurement would be subject to review by the Illinois Commerce Commission. These ZECs are out-of-market subsidies that threaten to artificially suppress prices in the PJM auctions.  On February 14, 2017, NRG, along with other companies, filed a complaint in the District Court for the Northern District of Illinois; another plaintiff group filed a similar complaint on the same day.  

As a result of the ZEC scheme adopted by the Illinois legislature and to address the effect of subsidies set to be paid to Illinois to certain nuclear units, on January 9, 2017, NRG and other generators and its trade association filed a joint amendment to the pending complaint seeking to apply the MOPR in the capacity market to existing resources that receive out-of-market subsidies. This amendment is to the March 21, 2016 complaint filed by NRG and other companies related to ratepayer-funded subsidies approved by the PUCO.

Midwest Generation, LLC Reactive Power Compensation — On June 21, 2016, FERC issued an order directing MWG to make a compliance filing setting forth refunds for payments received in violation of its 2004 reactive power settlement or to show cause why it has not violated the settlement. FERC also ordered MWG to revise its tariff to reflect the costs of units continuing to provide reactive power or show cause why it should not be required to do so. The Commission also referred this matter to the Commission's Office of Enforcement. On June 30, 2016, MWG filed a revised tariff, and on July 22, 2016, MWG made a compliance filing as ordered by FERC. On October 13, 2016, FERC found that MWG should only be liable for refunds that accrued after bankruptcy on April 1, 2014 through June 30, 2016. MWG is currently in settlement discussions regarding its revised reactive power schedule. The matter is still pending at the Commission's Office of Enforcement.
New England
2020/2021 ISO-NE Auction Results — On February 6, 2017, ISO-NE announced the results of its 2020/2021 forward capacity auction. NRG cleared 2,641 MW at $5.297 KW per month providing expected annual capacity revenues of $167.9 million. The 333 MWs at Canal Unit 3, which previously cleared the tenth forward capacity auction with a seven year price lock at a price of $7.17 KW per month for the 2020/2021 deliverability year, are excluded from these results.

Peak Energy Rent Adjustment Complaint — On September 30, 2016, the New England Power Generators Association, or NEPGA, filed a complaint against ISO-NE asking FERC to find the Peak Energy Rent, or PER, unjust and unreasonable. On January 9, 2017, FERC granted NEPGA’s complaint requiring a change to how the PER strike price is calculated and determine any refunds during the time period provided for in the complaint. The first FERC-ordered settlement conference occurred on February 16, 2017.
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 forward capacity market 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 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.
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. FERC denied rehearing. The NEPGA filed a petition for review of FERC's decision with the D.C. Circuit. Briefing is complete.
New York
Dunkirk Power Reliability Service and Natural Gas Addition On February 13, 2014, Dunkirk Power LLC and National Grid agreed to a term sheet for a 10-year agreement to govern the addition of natural gas-burning capabilities to the Dunkirk facility. This term sheet, known as the DNG Agreement Term Sheet, was approved by the NYSPSC on June 13, 2014. On February 27, 2015, Entergy filed a complaint in the U.S. District Court for the Northern District of New York alleging that the NYSPSC’s approval of the DNG Agreement Term Sheet impermissibly interfered with FERC’s exclusive jurisdiction over the wholesale markets. Entergy moved to withdraw the lawsuit, and on November 18, 2016, the U.S. District Court dismissed the lawsuit with prejudice.

27


 
New York Clean Energy Standard and Zero Emission Credit Nuclear Bailout — On August 1, 2016, the NYSPSC issued its Clean Energy Standard, or CES, order.  The CES order included three main components: (i) a commitment to move New York to 50% renewables by 2030; (ii) new renewable energy credit pricing for both new and existing renewable facilities; and (iii) a ZEC that would provide more than $7.6 billion over 12 years in out-of-market subsidy payments to certain selected nuclear generating units in the state. The stated purpose of the ZECs is to keep nuclear units running even though they would be uneconomic and likely retire if they received compensation only from the FERC-jurisdictional wholesale power market. The ZECs would have the effect of suppressing wholesale market prices and interfere with the wholesale market.  On October 19, 2016, NRG, along with other entities, filed a complaint in the U.S. District Court for the Southern District of New York, challenging the validity of the NYSPSC action and the ZEC program. On December 9, 2016, Exelon, the NYSPSC and other parties filed a motion to dismiss the complaint. On January 6, 2017, NRG, along with other parties, filed an opposition to the motions to dismiss. The motions are pending before the U.S. District Court.
Independent Power Producers of New York (IPPNY) Complaint — On January 9, 2017, EPSA requested FERC to promptly direct the NYISO to file tariff provisions to address pending market concerns related to out of market payments to existing generation in the NYISO. This request was prompted by the ZEC program initiated by the NYSPSC. This request follows IPPNY’s complaint at FERC against the NYISO on May 10, 2013, as amended on March 25, 2014. 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. Failure to implement buyer-side mitigation measures could result in uneconomic entry, which artificially decreases capacity prices below competitive market levels.
New York Public Service Commission Retail Energy Market Proceedings — On February 23, 2016, the NYSPSC issued what it refers to as its “Retail Reset” order, or Reset Order, in docket 12-M-0476 et al.  Among other things, the Reset Order instituted a price cap on energy supply offers and required many retail providers to seek affirmative consent from certain retail customers over a very short period of time to retain those customers.  Retail suppliers who cannot meet these conditions will be required to return their customers to energy supply service provided by the local utility. On July 25, 2016, the New York Supreme Court vacated part of the Reset Order on procedural grounds and remanded the matter to the NYSPSC for further consideration. Additionally, the Court affirmed the NYSPSC’s authority to regulate Energy Service Companies prices.  The matter is now on appeal before the Supreme Court of New York, Appellate Division. On December 2, 2016 in the same docket, the NYSPSC issued notice of an evidentiary proceeding and collaborative process to determine the future structure of the retail energy market in New York.  The outcome of this evidentiary and collaborative process, combined with the outcome of the appeal of the Reset Order, could affect the viability of the New York retail energy market. 
Gulf Coast Region
ERCOT
Greens Bayou Unit 5 RMR Status — On March 29, 2016, NRG filed notice with ERCOT of its intent to mothball Greens Bayou Unit 5.  On May 27, 2016, ERCOT made a final determination that the unit is needed for reliability must-run, or RMR, service to address potential operational contingencies. On June 14, 2016, the ERCOT Board confirmed ERCOT’s determination and approved a two-year RMR agreement, effective June 1, 2016 through June 30, 2018; provided, however, ERCOT may terminate the RMR agreement at any time upon 90 days' notice.  ERCOT has a standard form contract that provides for recovery of the operating costs of the unit, together with additional performance metrics and incentives.  The estimated budget for the unit is $58 million for the contract period, which amount does not include any incentives.  Under the RMR agreement, the unit is only available to ERCOT during the months of June through September.  On July 13, 2016, ERCOT issued a request for proposals for alternatives to the RMR agreement. No alternatives were selected by ERCOT. As a result of rule changes, ERCOT determined that the RMR agreement is only needed until a new 1,100 MW combined cycle plant at Colorado Bend Generating Station comes on line, expected in mid-2017.

MISO
Revisions to MISO Capacity Construct — On November 20, 2015, FERC issued a final order denying NRG’s request for rehearing of a 2012 FERC order approving the MISO capacity construct. NRG filed a petition for review of FERC’s decision with the D.C. Circuit on the grounds that FERC’s order denies merchant generators in MISO’s footprint any reasonable opportunity to recover their fixed costs. On November 2, 2016, NRG filed its initial brief and briefing continues. The eventual outcome of this proceeding could impact MISO’s attempts to redesign its capacity markets and thereby affect the value of NRG’s uncontracted assets within the MISO footprint.


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MISO Forward Capacity Market Design for Retail Choice States— MISO staff has proposed revisions to its market design by implementing a three-year Forward Resource Auction for Illinois and the portion of Michigan with Retail Choice Load with a Sloped Demand Curve.  On November 1, 2016, MISO filed its proposal with FERC. On December 14, 2016, NRG filed a protest to MISO’s proposal.  On February 2, 2017, FERC rejected MISO’s proposal. 

West Region
CAISO
Carlsbad Energy Center — On May 21, 2015, the CPUC approved the Carlsbad Energy Center PPTA for a nominally rated 500 MW five unit natural gas peaking plant. On December 7, 2015, three parties filed two petitions for a writ of review with the California Court of Appeal appealing the CPUC's decision. On November 30, 2016, the California Court of Appeals issued a decision affirming the CPUC's approval of the PPTA. The period in which to seek review of that decision in the California Supreme Court has passed, and the CPUC’s decision is now final.
Puente Power Project — On May 26, 2016, the CPUC approved the resource adequacy purchase agreement, or RAPA, between SCE and NRG for the construction of the 262 MW natural gas peaking Puente Power Project. On July 1, 2016, four different parties sought rehearing of the CPUC's approval of the RAPA. On December 1, 2016, the CPUC affirmed approval of the RAPA in a rehearing decision. On January 4, 2017, a petition for writ of review was filed in the California Court of Appeal seeking to reverse the CPUC's approval of the RAPA.
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 that governmental permits and approvals be obtained before construction and during operation of power plants. NRG is also subject to laws regarding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. New requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species have been put in place in recent years. Future laws may require the addition of emissions controls or other environmental controls or impose restrictions on the operations of the Company's facilities, which could have a material effect on the Company's operations. Complying with environmental laws involves significant capital and operating expenses. NRG decides to invest capital for environmental controls based on the relative certainty of the requirements, an evaluation of compliance options, and the expected economic returns on capital.  
A number of regulations with the potential to affect the Company and its facilities are in development, under review or have been recently promulgated by the EPA, including ESPS/NSPS for GHGs, ash disposal requirements, NAAQS revisions and implementation and effluent guidelines. NRG is currently reviewing the outcome and any resulting impact of recently promulgated regulations and cannot fully predict such impact until legal challenges are resolved and the new presidential administration decides how to proceed with some of the more controversial regulations. Federal and state environmental laws generally have become more stringent over time, although this trend could change in the near term with respect to federal laws under the new U.S. presidential administration.
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 historically become more stringent. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent NAAQS could 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.
Ozone NAAQS — On October 26, 2015, the EPA promulgated a rule that reduces the ozone NAAQS to 0.070 ppm. If it survives legal challenges, this more stringent NAAQS will obligate the states to develop plans to reduce NOx (an ozone precursor), which could affect some of the Company's units.

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Cross-State Air Pollution Rule — The EPA finalized CSAPR in 2011, which was intended to replace CAIR in January 2012, to address certain states' obligations to reduce emissions so that downwind states can achieve federal air quality standards. In December 2011, the D.C. Circuit stayed the implementation of CSAPR and then vacated CSAPR in August 2012 but kept CAIR in place until the EPA could replace it. In April 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 in November 2014 amended the CSAPR compliance dates. Accordingly, CSAPR replaced CAIR on January 1, 2015. On July 28, 2015, the D.C. Circuit held that the EPA had exceeded its authority by requiring certain reductions that were not necessary for downwind states to achieve federal standards. Although the D.C. Circuit kept the rule in place, the court ordered the EPA to revise the Phase 2 (or 2017) (i) SO2 budgets for four states including Texas and (ii) ozone-season NOx budgets for 11 states including Maryland, New Jersey, New York, Ohio, Pennsylvania and Texas. On October 26, 2016, the EPA finalized the CSAPR Update Rule, which reduces future NOx allocations and discounts the current banked allowances to account for the more stringent 2008 Ozone NAAQS and to address the D.C. Circuit's July 2015 decision. This rule has been challenged in the D.C. Circuit. The Company believes its investment in pollution controls and cleaner technologies leave the fleet well-positioned for compliance.
MATS — In February 2012, the EPA promulgated standards (the MATS rule) 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 had to be met beginning in April 2015 (with some units getting a 1-year extension). In June 2015, the U.S. Supreme Court issued a decision in the case of Michigan v. EPA, and held that the EPA unreasonably refused to consider costs when it determined that it was "appropriate and necessary" to regulate HAPs emitted by electric generating units. The U.S. Supreme Court did not vacate the MATS rule but rather remanded it to the D.C. Circuit for further proceedings. In December 2015, the D.C. Circuit remanded the MATS rule to the EPA without vacatur. On April 25, 2016, the EPA released a supplemental finding that the benefits of this regulation outweigh the costs to address the U.S. Supreme Court's ruling that the EPA had not properly considered costs. This finding has been challenged in the D.C. Circuit. While NRG cannot predict the final outcome of this rulemaking, NRG believes that because it has already invested in pollution controls and cleaner technologies, the fleet is well-positioned to comply with the MATS rule.
Clean Power Plan — The attention in recent years on GHG emissions has resulted in federal regulations and state legislative and regulatory action. In October 2015, the EPA finalized the Clean Power Plan, or CPP, addressing GHG emissions from existing EGUs. On February 9, 2016, the U.S. Supreme Court stayed the CPP. The D.C. Circuit, sitting en banc, heard oral argument on the legal challenges to the CPP in September 2016. Due to the ongoing litigation and the potential impact of the new U.S. presidential administration, the Company believes the CPP is not likely to survive.

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CO2 Emissions — NRG emits CO2 when generating electricity at most of its facilities. The graphs presented below illustrate NRG's U.S. Scope 1 emissions of CO2e for 2014, 2015 and 2016. The percentage of Scope 1 emissions covered under emissions-limiting regulations is 18% and the percentage of Scope 1 emissions covered under emission-reporting regulations is 82%. NRG anticipates reductions in its future emissions profile as the Company modernizes the fleet through repowering, improves generation efficiencies, and explores methods to capture CO2. From 2015 to 2016, the Company's CO2e emissions decreased from 86 million metric tons to approximately 66 million metric tons, representing a 19% reduction year over year. Factors leading to the decreased emissions include reductions in fleetwide annual net generation due to an overall decrease in market demand and a market-driven shift towards increased generation from natural gas over coal. The Company's goal is to reduce its total U.S. Scope 1, 2 and 3 CO2e emissions by 50% by 2030, and 90% by 2050, using 2014 as a baseline.
a10k2016emissions.jpg
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 outcome of the legal challenges, regulatory design, level of GHG reductions, the availability of offsets, actions of the new U.S. presidential administration, 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.
 Byproducts, Wastes, Hazardous Materials and Contamination
In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. The Company has evaluated the impact of the new rule on the Company's consolidated financial position, results of operations, or cash flows and has accrued its environmental and asset retirement obligations under the rule based on current estimates as of December 31, 2016.



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Domestic Site Remediation Matters
Under certain federal, state and local environmental laws, 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 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.
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 Nuclear Waste Policy 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 Nuclear Waste Policy Act through December 31, 2013, which was extended through an addendum dated January 24, 2014, to December 31, 2016. On December 12, 2016, STPNOC received the federal government's offer of another three-year extension of payment for continued failure to accept SNF and HLW. The proposal has been reviewed for adequacy and, with advice of counsel, was accepted. 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.
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 have become more stringent and imposed new requirements.
Once Through Cooling Regulation — In August 2014, EPA finalized the regulation regarding the use of water for once through cooling at existing facilities to address impingement and entrainment concerns. NRG anticipates that more stringent requirements will be incorporated into some of its water discharge permits over the next several years as NPDES permits are renewed.
Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which will impose more stringent requirements (as individual permits are renewed) for wastewater streams from flue gas desulfurization, fly ash, bottom ash, and flue gas mercury control. The Company estimates that it would cost approximately $200 million over the next eight years (the majority of the cost would be incurred after 2019) to comply with this rule at 11 coal-fired plants. This regulation has been challenged and is subject to legal uncertainty. The change in U.S. presidential administration increases the likelihood that the legal challenges will succeed. The Company decides to invest capital for environmental controls based on: the certainty of regulations; evaluation of different technologies; options to convert to gas; and the expected economic returns on the capital. Over the next several years, the Company will decide whether to proceed with these investments at each of the plants as permits are renewed based on, among other things, the legal certainty of the regulation and market conditions at that time.

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Regional Environmental Developments
East Region
New Source Review — 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.
Burton Island Old Ash Landfill — 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, or the VCP. On February 4, 2008, DNREC issued findings that no further action was 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. 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. In December 2015, DNREC approved the Company's remediation design and the Company's Long Term Stewardship Plan. The cost of completing the work required by the approved remediation plan is consistent with amounts budgeted in early 2016 and on track for completion in 2017. The estimated cost to comply with the Long-Term Stewardship Plan was added to the liability in December 2016.
In addition to the VCP, 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.
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 through 2020. The nine RGGI states are re-evaluating the program and may alter the rules to further reduce the number of allowances. The revisions being currently contemplated could adversely impact NRG's results of operations, financial condition and cash flows.
Massachusetts Global Warming Solutions Act Proposed Regulation In May 2016, the Massachusetts Supreme Judicial Court held that Massachusetts DEP had not complied with the 2008 Global Warming Solutions Act, which requires establishing limits for sources of GHGs. The Court held that participation in RGGI was not sufficient.  In December 2016, the Massachusetts DEP proposed a regulation that would limit GHG emissions from large electric generating facilities located in Massachusetts.  A final regulation is expected by August 2017.  If promulgated in its current form, the regulation may limit the operations of affected facilities.
Gulf Coast Region
Texas Regional Haze — In January 2016, the EPA promulgated a final rule that requires 15 coal-fired units (at eight plants in Texas) to reduce their SO2 rates at various times over the next five years if the rule survives legal challenges.  This Regional Haze rule was promulgated under the portion of the CAA that seeks to improve visibility at national parks.  Eight of these 15 units already have scrubbers and seven do not.  NRG owns two of the affected units, Limestone units 1 and 2, which already have scrubbers.  The rule requires that the Limestone units reduce their SO2 emission rates by 2019.  In July 2016, the U.S. Court of Appeals for the Fifth Circuit stayed the rule pending resolution of the legal challenges. On December 2, 2016, the EPA filed a motion in the Fifth Circuit for partial voluntary remand and partial lifting of the stay, but did not request vacatur of the final rule.



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Illinois Union Insurance Company Litigation — On October 2, 2015, the U.S. District Court for the Middle District of Louisiana issued an order granting LaGen’s motion for summary judgment on its claims for declaratory judgment and breach of contract against ILU for its failure to indemnify LaGen for the costs LaGen paid pursuant to the consent decree that resolved the NSR lawsuit which was brought by the U.S. EPA and LA DEQ against LaGen related to Big Cajun II. The court entered judgment in favor of LaGen for approximately $27 million. In addition, the court ruled that LaGen is entitled to approximately $7 million for future consent decree costs as they are incurred. On October 14, 2015, ILU filed a motion to stay execution of the judgment, which was granted on October 19, 2015. Also, on October 14, 2015, ILU filed a notice to appeal the judgment. On January 14, 2016, the U.S. District Court granted LaGen's motion for attorney's fees of approximately $2 million for the indemnity phase of the litigation. On January 29, 2016, ILU filed an appeal brief with the U.S. Court of Appeals for the Fifth Circuit. The Court of Appeals issued a decision on August 4, 2016 which vacated the summary judgment ruling and remanded the case to the U.S. District Court. The remanded case has been set for trial on May 8, 2017.
Environmental Capital Expenditures
NRG estimates that environmental capital expenditures from 2017 through 2021 required to comply with environmental laws will be approximately $134 million which includes $61 million for GenOn and $42 million for Midwest Generation. These costs are primarily associated with the cost of complying with anticipated ELG requirements.
Customers
NRG sells to a wide variety of customers. No individual customer accounted for 10% or more of NRG's total revenue in 2016. 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. NRG also receives significant revenues from PJM in its capacity as the regional transmission organization for the PJM footprint.
Employees
As of December 31, 2016, NRG and its consolidated subsidiaries, including GenOn and NRG Yield, Inc., had 8,763, employees, approximately 30% of whom were covered by U.S. bargaining agreements. During 2016, 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.
Risks Related to the Operation of NRG's Business
There is substantial doubt about GenOn's ability continue as a going concern.  GenOn’s inability to continue as a going concern could have a material impact on the Company.

As disclosed in Item 15 - Note 1, Nature of Business, and Note 12, Debt and Capital Leases, to this Form 10-K, as of December 31, 2016, $691 million of GenOn's Senior Notes outstanding, excluding $8 million of associated premiums, are current within the GenOn consolidated balance sheet and are due on June 15, 2017. GenOn's future profitability continues to be adversely affected by (i) a sustained decline in natural gas prices and its resulting effect on wholesale power prices and capacity prices, and (ii) the inability of GenOn Mid-Atlantic and REMA to make distributions of cash and certain other restricted payments to GenOn. Based on current projections, GenOn is not expected to have sufficient liquidity exclusive of cash subject to the restrictions under the GenOn Mid-Atlantic and REMA operating leases to repay the GenOn Senior Notes due in June 2017. As a result, there is substantial doubt about GenOn's ability to continue as a going concern. As a result of the substantial doubt about GenOn’s ability to continue as a going concern, along with additional factors, there is substantial doubt about certain of GenOn’s subsidiaries’ ability to continue as a going concern.
As of December 31, 2016, GenOn has consolidated cash and cash equivalents of $1.0 billion, of which $471 million and $100 million is held by GenOn Mid-Atlantic and REMA, respectively. Under their respective operating leases, GenOn Mid-Atlantic and REMA are not permitted to make any distributions and other restricted payments unless: (a) they satisfy the fixed charge coverage ratio for the most recently ended period for four fiscal quarters; (b) they are projected to satisfy the fixed charge coverage ratio for each of the two following periods of four fiscal quarters, commencing with the fiscal quarter in which such payment is proposed to be made; and (c) no significant lease default or event of default has occurred and is continuing. Additionally, GenOn Mid-Atlantic and REMA must be in compliance with the requirement to provide credit support to the owner lessors securing their obligations to pay scheduled rent under their respective leases. As a result, GenOn Mid-Atlantic has not been able to make distributions of cash and certain other restricted payments since the quarter ended March 31, 2014 which was the last quarterly period for which GenOn Mid-Atlantic satisfied the conditions under its operating agreement. REMA has not satisfied the conditions under its operating agreement to make distributions of cash and certain other restricted payments since GenOn was acquired by NRG in December 2012.
The Company, GenOn's parent company, has no obligation to provide any financial support to GenOn other than under the secured intercompany revolving credit agreement between the Company and GenOn and NRG Americas. As of December 31, 2016, $228 million was available to be used by GenOn under the $500 million revolving credit agreement. As controlled group members, ERISA requires that NRG and GenOn are jointly and severally liable for the NRG Pension Plan for Bargained Employees and the NRG Pension Plan, including the pension liabilities associated with GenOn employees.

GenOn is currently considering all options available to it, including negotiations with creditors, refinancing the GenOn Senior Notes, potential sales of certain generating assets as well as the possibility for a need to file for protection under Chapter 11 of the U.S. Bankruptcy Code. During 2016, GenOn appointed two independent directors, retained advisors and established a separate audit committee as part of this process.
The Company cannot assure you that GenOn’s inability to continue as a going concern will not have a material impact on the Company's statement of operations, cash flows and financial position including, among other things, if GenOn were to file for bankruptcy protection.

As of December 31, 2016, GenOn represents 15.6% of the Company's consolidated total assets, 16.9% of the Company's consolidated total liabilities and contributed $94 million to the Company's consolidated cash from operations in 2016.



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NRG's financial performance may be impacted by price fluctuations in the wholesale power and natural gas, coal and oil markets and other market factors that are beyond the Company's control.
Market prices for power, capacity, ancillary services, natural gas, coal and oil are unpredictable and 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 due to 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 as a result of the development of new plants, expansion of existing plants, the continued operation of uneconomic power plants due to state subsidies, or additional transmission capacity;
environmental regulations and legislation;
electric supply disruptions, including plant outages and transmission disruptions;
changes in power transmission infrastructure;
fuel transportation capacity constraints or inefficiencies;
weather conditions, including extreme weather conditions and seasonal fluctuations, including the effects of climate change;
changes in commodity prices and the supply of commodities, including but not limited to natural gas, coal and oil;
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, new technologies and new forms of competition for the production of power;
fuel price volatility;
economic and political conditions;
regulations and actions of the ISOs and RTOs;
federal and state power regulations and legislation;
changes in law, including judicial decisions;
changes in prices related to RECs; and
changes in capacity prices and capacity markets.
Such factors and the associated fluctuations in power prices have affected the Company's wholesale power operating results in the past and will continue to do so in the future.
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 costs, results of operations, financial condition and cash flows could be adversely impacted by disruption of its fuel supplies.
NRG relies on natural gas, coal and oil 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.

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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 power sales 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.
Changes in the price of coal and natural gas could cause the Company to hold excess coal inventories and incur contract termination costs.
Low natural gas prices can cause natural gas to be the more cost-competitive fuel compared to coal for generating electricity. Because the Company enters into guaranteed supply contracts to provide for the amount of coal needed to operate its base load coal-fired generating facilities, the Company may experience periods where it holds excess amounts of coal if fuel pricing results in the Company reducing or idling coal-fired generating facilities. In addition, the Company may incur costs to terminate supply contracts for coal in excess of its generating requirements.

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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' wholesale electricity 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 businesses' wholesale electricity supply costs rise at a greater rate than the rates it charges to customers. The price of wholesale electricity supply purchases associated with the retail businesses' 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 retail businesses' earnings and cash flows could also be adversely affected in any period in which its customers' actual usage of electricity significantly varies from the forecasted usage, which could occur due to, among other factors, weather events, competition and economic conditions.
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 2017 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.
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.

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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 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.
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, NRG 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.

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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 non-performance penalties or require NRG to incur significant costs as a result of running one of its higher cost units or obtaining replacement power from third parties in the open market to satisfy the Company's forward power sales obligations. NRG's inability to operate the Company's plants efficiently, manage capital expenditures and costs, and generate earnings and cash flow from the Company's asset-based businesses could have a material adverse effect on the Company's results of operations, financial condition or cash flows. While NRG maintains insurance, obtains warranties from vendors and obligates contractors to meet certain performance levels, the proceeds of such insurance, warranties or performance guarantees may not be adequate to cover the Company's lost revenues, increased expenses or liquidated damages payments should the Company experience equipment breakdown or non-performance by contractors or vendors.
Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks such as earthquake, flood, lightning, hurricane and wind, other hazards, such as fire, explosion, structural collapse and machinery failure are inherent risks in the Company's operations. These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in NRG being named as a defendant in lawsuits asserting claims for substantial damages, including for environmental cleanup costs, personal injury and property damage and fines and/or penalties. NRG maintains an amount of insurance protection that it considers adequate, but the Company cannot provide any assurance that its insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which it may be subject. A successful claim for which the Company is not fully insured could hurt its financial results and materially harm NRG's financial condition. 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 flows and financial condition.
Many of NRG's facilities are old and require periodic upgrading, improvement, maintenance and repair. 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.

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The Company may incur additional costs or delays in the development, construction and operation of new plants, improvements to existing plants, or the implementation of environmental control equipment at existing plants and may not be able to recover their investment or complete the project.
The Company is 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 risks, including:
inability to obtain sufficient funding on reasonable terms and/or necessary government financial incentives;
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, including those related to climate change;
unanticipated cost overruns;
exchange rate risks; and
failure of contracting parties to perform under contracts, including EPC contractors.
Any of these risks could cause NRG's financial returns on new investments to be lower than expected or could cause the Company to operate below expected capacity or availability levels, which could result in lost revenues, increased expenses, higher maintenance costs and penalties. Insurance is maintained to protect against these risks, warranties are generally obtained for limited periods relating to the construction of each project and its equipment in varying degrees, and contractors and equipment suppliers are obligated to meet certain performance levels. The insurance, warranties or performance guarantees, however, may not be adequate to cover increased expenses. As a result, a project may cost more than projected and may be unable to fund principal and interest payments under its construction financing obligations, if any. A default under such a financing obligation could result in 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.

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The Company's development programs are subject to financing and public policy risks that could adversely impact NRG's financial performance or result in the abandonment of such development projects.
While NRG currently intends to develop and finance its 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 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 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-related mandates or controls. 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.
The Company’s renewables business has a pipeline of projects across the utility scale and distributed generation markets, including both organically developed projects and projects acquired from third-parties. If a number of the projects fail to proceed to construction or are not completed, the Company’s business, financial condition or operating results could be materially adversely affected.

The development process is long and includes many steps such as project siting, financing, construction, permitting, government approvals and the negotiation of project development agreements. There can be no assurance that the projects in the Company’s renewables project pipeline will be completed on schedule or within budget, generate revenues, receive the necessary financing for construction, among other risks. As the Company develops its renewables project pipeline, some of the projects in the pipeline may not be completed or proceed to construction as a result of various factors. These factors may include changes in applicable laws and regulations, including government incentives, environmental concerns regarding a project or changes in the economics related to a project, including the ability to finance a particular project. If a number of projects are not completed, the Company’s business, financial condition or operating results could be materially adversely affected.

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.

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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.
The Company'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 the Company's retail businesses.
The Company's retail businesses face competition for customers. Competitors may offer different products, lower prices, and other incentives, which may attract customers away from NRG's retail businesses. In some retail electricity markets, the principal competitor may be the incumbent utility. The incumbent utility has the advantage of long-standing relationships with its customers and strong brand recognition. Furthermore, NRG'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 and its retail businesses.
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.
The Company’s use and enjoyment of real property rights for its projects may be adversely affected by the rights of lienholders and leaseholders that are superior to those of the grantors of those real property rights to the Company.
 
Solar and wind projects generally are, and are likely to be, located on land occupied by the project pursuant to long-term easements and leases. The ownership interests in the land subject to these easements and leases may be subject to mortgages securing loans or other liens (such as tax liens) and other easement and lease rights of third parties (such as leases of oil or mineral rights) that were created prior to the project’s easements and leases. As a result, the project’s rights under these easements or leases may be subject, and subordinate, to the rights of those third parties. The Company performs title searches and obtains title insurance to protect itself against these risks. Such measures may, however, be inadequate to protect the Company against all risk of loss of its rights to use the land on which the renewable projects are located, which could have a material adverse effect on the Company’s business, financial condition and results of operations.

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 voting interest in NRG Yield, Inc. and the position of certain of its executive officers that are serving on the Board of Directors of NRG Yield, Inc. or as executive officers 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 the ownership interests 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 materially 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, 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, 2016, approximately 30% 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 flows. In addition, a number of the Company's employees at NRG's plants are close to retirement. The Company's inability to replace retiring workers could create potential knowledge and expertise gaps as such workers retire.
Changes in technology may impair the value of NRG's power plants.
Research and development activities are ongoing to provide alternative and more efficient technologies to produce power, including "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 flows, results of operations or competitive position.

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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 flows. In addition, significant weather events or terrorist actions could damage or shut down the power transmission and distribution facilities upon which the Company's retail businesses are dependent. Power supply may be sold at a loss if these events cause a significant loss of retail customer load.
The operation of NRG’s businesses is subject to cyber-based security and integrity risk.
Numerous functions affecting the efficient operation of NRG’s businesses are dependent on the secure and reliable storage, processing and communication of electronic data and the use of sophisticated computer hardware and software systems. The operation of NRG’s generation plants, including STP, and of NRG's energy and fuel trading businesses are reliant on cyber-based technologies and, therefore, subject to the risk that such systems could be the target of disruptive actions, particularly through cyber-attack or cyber intrusion, including by computer hackers, foreign governments and cyber terrorists, or otherwise be compromised by unintentional events. As a result, operations could be interrupted, property could be damaged and sensitive customer information could be lost or stolen, causing NRG to incur significant losses of revenues, other substantial liabilities and damages, costs to replace or repair damaged equipment and damage to NRG's reputation. In addition, NRG may experience increased capital and operating costs to implement increased security for its cyber systems and plants.
The Company's retail businesses are subject to the risk that sensitive customer data may be compromised, which could result in an adverse impact to its reputation and/or the results of operations of the Company's retail businesses.
The Company'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, driver's license numbers, social security numbers and bank account information. NRG'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's retail businesses. If a significant breach occurred, the reputation of NRG and its retail businesses may be adversely affected, customer confidence may be diminished, or NRG 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.
Risks Related to Governmental Regulation and Laws
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 legal and regulatory regimes may cause the Company to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of a non-complying facility, the imposition of liens, fines, and/or civil or criminal liability.

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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 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 a material adverse effect on the rates NRG charges for power from its facilities.
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, non-performance penalties 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 a material 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 reinstate the vertical monopoly utility of the markets or require divestiture by generating companies to reduce their market share. 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. In addition, since 2010, there have been a number of reforms to the regulation of the derivatives markets, both in the United States and internationally. These regulations, and any further changes thereto, or adoption of additional regulations, including any regulations relating to position limits on futures and other derivatives or margin for derivatives, could negatively impact NRG’s ability to hedge its portfolio in an efficient, cost-effective manner by, among other things, potentially decreasing liquidity in the forward commodity and derivatives markets or limiting NRG’s ability to utilize non-cash collateral for derivatives transactions.
NRG’s business may be affected by state interference in the competitive wholesale marketplace.
NRG’s legacy generation and competitive retail businesses rely on a competitive wholesale marketplace. The competitive wholesale marketplace may be undermined by out-of-market subsidies provided by states or state entities, including bailouts of uneconomic nuclear plants, imports of power from Canada, renewable mandates or subsidies, as well as out-of-market payments to new generators. These out-of-market subsidies to existing or new generation undermine the competitive wholesale marketplace, which can lead to premature retirement of existing facilities, including those owned by the Company. If these measures continue, capacity and energy prices may be suppressed, and the Company may not be successful in its efforts to insulate the competitive market from this interference.

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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, PTCs, cash grants in lieu of ITCs, loan guarantees, RPS programs, modified accelerated cost-recovery system of depreciation and bonus depreciation. For example, in December 2015, the U.S. Congress enacted an extension of the 30% solar ITC so that projects which began construction in 2016 through 2019 will continue to qualify for the 30% ITC. Projects beginning construction in 2020 and 2021 will be eligible for the ITC at the rates of 26% and 22%, respectively. The same legislation also extended the 10-year wind PTC for wind projects which began construction in 2016 through 2019. Wind projects which begin construction in the years 2017, 2018 and 2019 are eligible for PTCs at 80%, 60% and 40% of the statutory rate per kWh, respectively.
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.
The integration of the Capacity Performance product into the PJM market and the Pay-for-Performance mechanism in ISO-NE could lead to substantial changes in capacity income and non-performance penalties, which could have a material adverse effect on NRG’s results of operations, financial condition and cash flows.

Both ISO-NE and PJM operate a pay-for-performance model where capacity payments are modified based on real-time generator performance. Capacity market prices are sensitive to design parameters, as well as additions of new capacity. NRG may experience substantial changes in capacity income and non-performance penalties, which could have a material adverse effect on NRG’s results of operations, financial condition and cash flows.

Certain of NRG's long-term bilateral contracts result from state-mandated procurements and 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 utilities that are regulated by their respective states, and have been entered into pursuant to certain state programs. Certain long-term contracts that other companies have with state-regulated utilities have been challenged in federal court and have been declared unconstitutional on the grounds that the rate for energy and capacity established by the contracts impermissibly conflicts with the rate for energy and capacity established by FERC pursuant to the FPA. If certain of the Company's state-mandated agreements with utilities are ever held to be invalid, NRG may be unable to replace such contracts, which could have a material adverse effect on NRG's business, financial condition, results of operations and cash flows.

47



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. STP Unit 1 was operating with a single-cycle license amendment issued on December 11, 2015 after a control rod was determined to be inoperable following a scheduled refueling and maintenance outage. The approved license amendment to support STP Unit 1 operation with the inoperable control rod and the associated control rod drive shaft removed was granted by the NRC on December 21, 2016.
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. 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.
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.
Federal and state environmental laws generally have become more stringent although this trend could change with respect to federal laws under the new U.S. presidential administration.

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NRG's businesses are subject to physical, market and economic risks relating to potential effects of climate change.

Climate change may produce changes in weather or other environmental conditions, including temperature or precipitation levels, and thus may impact consumer demand for electricity. In addition, the potential physical effects of climate change, such as increased frequency and severity of storms, floods and other climatic events, could disrupt NRG's operations and cause it to incur significant costs in preparing for or responding to these effects. These or other meteorological changes could lead to increased operating costs, capital expenses or power purchase costs. Climate change could also affect the availability of a secure and economical supply of water in some locations, which is essential for the continued operation of NRG's generation plants.
GHG regulation could increase the cost of electricity, particularly power generated by fossil fuels, and such increases could have a depressive effect on regional economies. Reduced economic and consumer activity in NRG's service areas — both generally and specific to certain industries and consumers accustomed to previously lower cost power — could reduce demand for the power NRG generates and markets. Also, demand for NRG's energy-related services could be similarly reduced by consumers’ preferences or market factors favoring energy efficiency, low-carbon power sources or reduced electricity usage.
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 2016 can be found in Item 1, Business — Environmental Matters. On October 23, 2015, the EPA promulgated the final GHG emissions rules for new and existing fossil-fuel-fired electric generating units. The impact of these newly promulgated rules and further legislation or regulation of GHGs on the Company's financial performance will depend on a number of factors, including the actions of the new U.S. presidential administration, the outcome of the legal challenges to promulgated regulations, and the extent to which NRG will 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 through 2020. The nine RGGI states are re-evaluating the program and may alter the rules to further reduce the number of allowances. The revisions being currently contemplated 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.
On October 26, 2015, the EPA promulgated a rule that reduces the ozone NAAQS to 0.070 ppm. If it survives legal challenges, this more stringent NAAQS will obligate the states to develop plans to reduce NOx (an ozone precursor), which could affect some of the Company's units.
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 retail businesses are subject to changing state rules and regulations that could have a material impact on the profitability of its business lines.
The competitiveness of NRG's retail businesses 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, which can include controls on the retail rates NRG's retail businesses can charge, the imposition of additional costs on sales, restrictions on the Company's ability to obtain new customers through various marketing channels and disclosure requirements, which can affect the competitiveness of NRG's retail businesses. Additionally, state or federal imposition of net metering or RPS programs can make it more or less expensive for retail customers to supplement or replace their reliance on grid power.  NRG's retail businesses have 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.   

49


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, which risks may negatively impact the Company's business.
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.
The Company may potentially be affected by emerging technologies that may over time affect change in capacity markets and the energy industry overall with the inclusion of distributed generation and clean technology.
Some technologies like, distributed renewable energy technologies, broad consumer adoption of electric vehicles and energy storage devices could affect the price of energy. These distributed technologies may affect the financial viability of utility counterparties and could have significant impacts on wholesale market prices.
Risks Related to Economic and Financial Market Conditions
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.

50


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.
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.
Adverse economic conditions could adversely affect NRG’s business, financial condition, results of operations and cash flows.
Adverse economic conditions and declines in wholesale energy prices, partially resulting from adverse economic conditions, may impact NRG’s earnings. The breadth and depth of negative economic conditions may have a wide-ranging impact on the U.S. business environment, including NRG’s businesses. In addition, adverse economic conditions also reduce the demand for energy commodities. Reduced demand from negative economic conditions continues to impact the key domestic wholesale energy markets NRG serves. The combination of lower demand for power and increased supply of natural gas has put downward price pressure on wholesale energy markets in general, further impacting NRG’s energy marketing results. In general, economic and commodity market conditions will continue to impact NRG’s unhedged future energy margins, liquidity, earnings growth and overall financial condition. In addition, adverse economic conditions, declines in wholesale energy prices, reduced demand for power and other factors may negatively impact the trading price of NRG’s common stock and impact forecasted cash flows, which may require NRG to evaluate its goodwill and other long-lived assets for impairment. Any such impairment could have a material impact on NRG’s financial statements.
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 the net deferred tax assets, which are predominantly related to NRG Yield, Inc., that the Company estimates as 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 accordingly 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.

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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, 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.



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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:
GenOn's and certain of its subsidiaries' ability to continue as a going concern;
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;
Changes in law, including judicial decisions;
Price mitigation strategies and other market structures employed by ISOs or RTOs that result in a failure to adequately and fairly compensate NRG's generation units;
NRG's ability to mitigate forced outage risk for units subject to capacity performance requirements in PJM, performance incentives in ISO-NE, and scarcity pricing in ERCOT;
NRG's ability to borrow 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 2016 Senior Credit Facility, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;
Cyber terrorism and inadequate cybersecurity, or the occurrence of a catastrophic loss and the possibility that NRG may not have adequate insurance to cover losses resulting from such hazards or the inability of NRG's insurers to provide coverage;
NRG's ability to develop and build new power generation facilities, including new renewable projects;
NRG's ability to develop and innovate new products as retail and wholesale markets continue to change and evolve;
NRG's ability to implement its strategy of finding ways to meet the challenges of climate change, clean air and protecting natural resources while taking advantage of business opportunities;
NRG's ability to increase cash from operations through operational and commercial initiatives, corporate efficiencies, asset strategy, and a range of other programs throughout NRG to reduce costs or generate revenues;
NRG's ability to sell assets to NRG Yield, Inc. and to close drop-down transactions;
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 engage in successful mergers and acquisitions activity;

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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.

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Item 2 — Properties
Listed below are descriptions of NRG's interests in facilities, operations and/or projects owned or leased as of December 31, 2016. The MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units as of December 31, 2016. The following table summarizes NRG's power production and cogeneration facilities by region:

Name of Facility
 
Power Market
 
Plant Type
 
Primary Fuel
 
Location
 
Rated MW Capacity
 
Net MW Capacity(a)
 
% Owned
      Gulf Coast Region
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Bayou Cove
 
MISO
 
Fossil
 
Natural Gas
 
LA
 
225

 
225

 
100.0

Big Cajun I
 
MISO
 
Fossil
 
Natural Gas
 
LA
 
430

 
430

 
100.0

Big Cajun II
 
MISO
 
Fossil
 
Coal
 
LA
 
580

 
580

 
100.0

Big Cajun II
 
MISO
 
Fossil
 
Natural Gas
 
LA
 
540

 
540

 
100.0

Big Cajun II
 
MISO
 
Fossil
 
Coal
 
LA
 
588

 
341

 
58.0

Cedar Bayou
 
ERCOT
 
Fossil
 
Natural Gas
 
TX
 
1,495

 
1,495

 
100.0

Cedar Bayou 4
 
ERCOT
 
Fossil
 
Natural Gas
 
TX
 
498

 
249

 
50.0

Choctaw(j)
 
TVA(f)
 
Fossil
 
Natural Gas
 
MS
 
800

 
800

 
100.0

Cottonwood
 
MISO
 
Fossil
 
Natural Gas
 
TX
 
1,263

 
1,263

 
100.0

Greens Bayou
 
ERCOT
 
Fossil
 
Natural Gas
 
TX