2017
Form 10-K
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year ended December 31, 2017.
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
No
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
No
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
No
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
No
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.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or emerging
growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of
the Exchange Act.
Large accelerated filer
Accelerated filer
Non-accelerated filer
Smaller reporting company
(Do not check if a smaller reporting
company)
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any
new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes
No
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 $4,880,501,096 based on the closing sale price of $17.22 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
Common Stock, par value $0.01 per share
Outstanding at January 31, 2018
317,637,917
Documents Incorporated by Reference:
Portions of the Registrant's definitive Proxy Statement relating to its 2018 Annual Meeting of Stockholders
are incorporated by reference into Part III of this Annual Report on Form 10-K
1
Stockholder information
STOCK TRANSFER AGENT AND REGISTRAR
Shareholder correspondence should be mailed to:
Computershare
P.O. BOX 505000
Louisville, KY 40233-5000
STOCKHOLDER INQUIRIES
Overnight correspondence should be sent to:
Computershare
462 South 4th Street, Suite 1600
Louisville, KY 40202
1.866.214.2213
Email: shareholder@computershare.com
Online inquires: https://www-us.computershare.com/investor/Contact
Website: www.computershare.com/investor
Send certificates for transfer and address changes to:
Computershare
P.O. BOX 505000
Louisville, KY 40233-5000
STOCK LISTING
NRG’s common stock is listed on the New York Stock Exchange
under the ticker symbol NRG.
FINANCIAL INFORMATION
NRG’s Annual Report on Form 10-K, Proxy Statement and other SEC Filings
are available at www.nrg.com under the Investors section.
TABLE OF CONTENTS
Glossary of Terms
GLOSSARY OF TERMS
PART I
Item 1 — Business
Item 1A — Risk Factors Related to NRG Energy, Inc.
Item 1B — Unresolved Staff Comments
Item 2 — Properties
Item 3 — Legal Proceedings
Item 4 — Mine Safety Disclosures
PART II
Item 5 — Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Item 6 — Selected Financial Data
Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A — Quantitative and Qualitative Disclosures About Market Risk
Item 8 — Financial Statements and Supplementary Data
Item 9 — Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9A — Controls and Procedures
Item 9B — Other Information
PART III
Item 10 — Directors, Executive Officers and Corporate Governance
Item 11 — Executive Compensation
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13 — Certain Relationships and Related Transactions, and Director Independence
Item 14 — Principal Accounting Fees and Services
PART IV
Item 15 — Exhibits, Financial Statement Schedules
Item 16 — Form 10-K Summary
EXHIBIT INDEX
3
10
10
34
53
54
58
58
59
59
61
62
112
116
116
116
118
119
119
122
122
122
123
124
124
239
228
2
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
2023 Term Loan Facility
The Company's $1.9 billion term loan facility due 2023, a component of the Senior Credit
Facility
AEP
American Electric Power
Adjusted EBITDA
Adjusted earnings before interest, taxes, depreciation and amortization
ARO
ASC
ASU
Asset Retirement Obligation
The FASB Accounting Standards Codification, which the FASB established as the source of
authoritative GAAP
Accounting Standards Updates – updates to the ASC
August 2017 Drop Down
Assets
Average realized prices
The remaining 25% interest in NRG Wind TE Holdco, which was sold to NRG Yield, Inc.
on August 1, 2017
Volume-weighted average power prices, net of average fuel costs and reflecting the impact
of settled hedges
AZNMSNV
Backlog
BACT
Bankruptcy Code
Bankruptcy Court
Baseload
BETM
BTU
Business Solutions
CAA
CAIR
CAISO
Carlsbad
CASPR
CCF
CDD
CDWR
CEC
CenterPoint
CFTC
Chapter 11 Cases
C&I
CES
Cleco
CO2
CO2e
COD
ComEd
Company
CPP
CPS
Arizona, New Mexico and Southern Nevada
Projects that are under construction, contracted, or awarded and represents a higher level of
execution certainty
Best Available Control Technology
Chapter 11 of Title 11 of the U.S. Bankruptcy Code
United States Bankruptcy Court for the Southern District of Texas, Houston Division
Units expected to satisfy minimum baseload requirements of the system and produce
electricity at an essentially constant rate and run continuously
Boston Energy Trading and Marketing LLC
British Thermal Unit
NRG's business solutions group, which includes demand response, commodity sales,
energy efficiency and energy management services
Clean Air Act
Clean Air Interstate Rule
California Independent System Operator
Carlsbad Energy Center, a 527 MW natural gas fired project located in Carlsbad, CA
Competitive Auctions with Sponsored Resources
Carbon Capture Facility
Cooling Degree Day
California Department of Water Resources
California Energy Commission
CenterPoint Energy Houston Electric, LLC
U.S. Commodity Futures Trading Commission
Voluntary cases commenced by the GenOn Entities under the Bankruptcy Code in the
Bankruptcy Court
Commercial, industrial and governmental/institutional
Clean Energy Standard
Cleco Energy LLC
Carbon Dioxide
Carbon Dioxide Equivalents
Commercial Operation Date
Commonwealth Edison
NRG Energy, Inc.
Clean Power Plan
Combined Pollutant Standard
3
CPUC
CSAPR
CVSR
CWA
D.C. Circuit
DGPV Holdco 1
DGPV Holdco 2
DGPV Holdco 3
Distributed Solar
DNREC
Dominion
Drop Down Assets
California Public Utilities Commission
Cross-State Air Pollution Rule
California Valley Solar Ranch
Clean Water Act
U.S. Court of Appeals for the District of Columbia Circuit
NRG DGPV Holdco 1 LLC
NRG DGPV Holdco 2 LLC
NRG DGPV Holdco 3 LLC
Solar power projects that primarily sell power to customers for usage on site, or are
interconnected to sell power into a local distribution grid
Delaware Department of Natural Resources and Environmental Control
Dominion Resources, Inc.
Collectively, the June 2014 Drop Down Assets, the January 2015 Drop Down Assets, the
November 2015 Drop Down Assets, the September 2016 Drop Down Assets, the March 2017
Drop Down Assets, the August 2017 Drop Down Assets, and the November 2017 Drop Down
Assets
DSI
DSU
Dry Sorbent Injection
Deferred Stock Unit
Economic gross margin
Sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels
and other cost of sales
El Segundo Energy Center
NRG West Holdings LLC, the subsidiary of Natural Gas Repowering LLC, which owns the
El Segundo Energy Center project
EME
EMAAC
Edison Mission Energy
Eastern Mid-Atlantic Area Council
Energy Plus Holdings
Energy Plus Holdings LLC
EPA
EPC
EPSA
ERCOT
ERISA
ESP
ESPP
ESPS
EWG
U.S. Environmental Protection Agency
Engineering, Procurement and Construction
The Electric Power Supply Association
The Employee Retirement Income Security Act of 1974
Electrostatic Precipitator
NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan
Existing Source Performance Standards
Exempt Wholesale Generator
Exchange Act
The Securities Exchange Act of 1934, as amended
FASB
FERC
FGD
FPA
Fresh Start
FTRs
GAAP
GenConn
GenOn
Financial Accounting Standards Board
Federal Energy Regulatory Commission
Flue gas desulfurization
Federal Power Act
Reporting requirements as defined by ASC-852, Reorganizations
Financial Transmission Rights
Accounting principles generally accepted in the U.S.
GenConn Energy LLC
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 Entities
GenOn Mid-Atlantic
GenOn Senior Notes
GenOn and certain of its wholly owned subsidiaries, including GenOn Americas Generation,
that filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the
Bankruptcy Court on June 14, 2017
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'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 $489 million of
9.875% senior notes due 2020
GHG
GIP
Greenhouse Gas
Global Infrastructure Partners
Green Mountain Energy
Green Mountain Energy Company
GW
GWh
HAP
HDD
Heat Rate
HLBV
IASB
IFRS
IPA
IPPNY
ISO
ISO-NE
ITC
Gigawatt
Gigawatt Hour
Hazardous Air Pollutant
Heating Degree Day
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
Hypothetical Liquidation at Book Value
International Accounting Standards Board
International Financial Reporting Standards
Illinois Power Agency
Independent Power Producers of New York
Independent System Operator, also referred to as RTOs
ISO New England Inc.
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
kWh
LaGen
LIBOR
LSE
LTIPs
LTSA
MAAC
Kilowatt-hour
Louisiana Generating LLC
London Inter-Bank Offered Rate
Load Serving Entities
Collectively, the NRG LTIP and the NRG GenOn LTIP
Long-Term Service Agreement
Mid-Atlantic Area Council
March 2017 Drop Down Assets
(i) 16% interest in the Agua Caliente solar project and (ii) NRG's interests in seven utility-
scale solar projects located in Utah, which were sold to NRG Yield, Inc. on March 27, 2017
Marsh Landing
Mass Market
MATS
MDE
MDth
Merger
Merger Agreement
NRG Marsh Landing, LLC (formerly known as GenOn Marsh Landing, LLC)
Residential and small commercial customers
Mercury and Air Toxics Standards promulgated by the EPA
Maryland Department of the Environment
Thousand Dekatherms
The merger completed on December 14, 2012 by NRG and GenOn pursuant to the Merger
Agreement
The agreement by and among NRG, GenOn and Plus Merger Corporation, dated as of July
20, 2012
Electric Reliability Council of Texas, the Independent System Operator and the regional
reliability coordinator of the various electricity systems within Texas
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
4
5
Midwest Generation
Midwest Generation, LLC
MISO
MMBtu
MOPR
MSU
MW
MWh
MWt
NAAQS
NEPGA
NEPOOL
NERC
Net Capacity Factor
Net Exposure
Net Generation
NJDEP
NOL
NOV
November 2015 Drop Down
Assets
November 2017 Drop Down
Assets
NOx
NPDES
NPNS
NQSO
NRC
NRG
Midcontinent Independent System Operator, Inc.
Million British Thermal Units
Minimum Offer Price Rule
Market Stock Unit
Megawatts
Saleable megawatt hour net of internal/parasitic load megawatt-hour
Megawatts Thermal Equivalent
National Ambient Air Quality Standards
New England Power Generators Association
New England Power Pool
North American Electric Reliability Corporation
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
Counterparty credit exposure to NRG, net of collateral
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
New Jersey Department of Environmental Protection
Net Operating Loss
Notice of Violation
75% of the Class B interests of NRG Wind TE Holdco, which owns a portfolio of 12 wind
facilities totaling 814 net MW
A 38 MW solar portfolio primarily comprised of assets from SPP funds, in addition to other
projects developed by NRG, which were sold to NRG Yield, Inc. on November 1, 2017
Nitrogen Oxides
National Pollutant Discharge Elimination System
Normal Purchase Normal Sale
Non-Qualified Stock Option
U.S. Nuclear Regulatory Commission
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 Energy, Inc. Amended and Restated Long-Term Incentive Plan
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 Operating 2024
Senior Notes
NRG Yield Operating 2026
Senior Notes
NRG Yield LLC
NRG Yield, Inc., the owner of 53.7% 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 LLC's $500 million of 5.375% unsecured senior notes due 2024
NRGY Yield Operating LLC's $350 million of 5.00% unsecured senior notes due 2026
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
NSR
New Source Performance Standards
New Source Review
6
Nuclear Decommissioning
Trust Fund
Nuclear Waste Policy Act
NYAG
NYISO
NYMEX
NYSPSC
OCI/OCL
Peaking
PER
Petition Date
Pipeline
PJM
PPA
PSD
PSU
PTC
PUCT
PUHCA
PURPA
QF
RCRA
Reliant Energy
REMA
Restructuring Support
Agreement
Retail
Revolving Credit Facility
RFP
RGGI
RMR
ROFO
ROFO Agreement
RPM
RPS
RPSU
RPV Holdco
RSU
RTO
NRG's nuclear decommissioning trust fund assets, which are for the Company's portion of
the decommissioning of the STP, units 1 & 2
U.S. Nuclear Waste Policy Act of 1982
State of New York Office of Attorney General
New York Independent System Operator
New York Mercantile Exchange
New York State Public Service Commission
Other Comprehensive Income/(Loss)
Units expected to satisfy demand requirements during the periods of greatest or peak load
on the system
Peak Energy Rent
June 14, 2017
Projects that range from identified lead to shortlisted with an offtake, and represents a
lower level of execution certainty
PJM Interconnection, LLC
Power Purchase Agreement
Prevention of Significant Deterioration
Performance Stock Unit
Production Tax Credit
Public Utility Commission of Texas
Public Utility Holding Company Act of 2005
Public Utility Regulatory Policies Act of 1978
Qualifying Facility under PURPA
Resource Conservation and Recovery Act of 1976
Reliant Energy Retail Services, LLC
NRG REMA LLC, which leases a 100% interest in the Shawville generating facility and 16.7%
and 16.5% interests in the Keystone and Conemaugh generating facilities, respectively
Restructuring Support and Lock-Up Agreement, dated as of June 12, 2017 and as amended
on October 2, 2017, by and among GenOn Energy, Inc., GenOn Americas Generation, LLC,
and subsidiaries signatory thereto, NRG Energy, Inc. and the noteholders signatory thereto
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
The Company's $2.5 billion revolving credit facility, a component of the 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
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
Request For Proposal
Regional Greenhouse Gas Initiative
Reliability Must-Run
Right of First Offer
Second Amended and Restated Right of First Offer Agreement by and between NRG
Energy, Inc. and NRG Yield, Inc.
Reliability Pricing Model
Renewable Portfolio Standards
Relative Performance Stock Unit
NRG RPV Holdco 1 LLC
Restricted Stock Unit
Regional Transmission Organization
7
RTR
SCE
SCR
SDG&E
SEC
Securities Act
Senior Credit Facility
Senior Notes
Services Agreement
Settlement Agreement
September 2016 Drop Down
Assets
SIFMA
SNF
SO2
South Central
SPP
S&P
STP
STPNOC
Tax Act
TCPA
Term Loan Facility
Texas Genco
Thermal Business
TSA
TSR
TVA
TWCC
TWh
UNFCCC
UPMC
U.S.
U.S. DOE
Renewable Technology Resource
Southern California Edison Company
Selective Catalytic Reduction Control System
San Diego Gas & Electric
U.S. Securities and Exchange Commission
The Securities Act of 1933, as amended
NRG's senior secured credit facility, comprised of the Revolving Credit Facility and the 2023
Term Loan 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
As of December 31, 2017, NRG's $4.8 billion outstanding unsecured senior notes consisting
of $992 million of 6.25% senior notes due 2022, $733 million of 6.25% senior notes due 2024,
$1.0 billion of the 7.25% senior notes due 2026, $1.25 billion of the 6.625% senior notes due
2027, and $870 million of 5.75% senior notes due 2028
NRG provided GenOn with various management, personnel and other services, which
include human resources, regulatory and public affairs, accounting, tax, legal, information
systems, treasury, risk management, commercial operations, and asset management, as set
forth in the services agreement with GenOn
A settlement agreement and any other documents necessary to effectuate the settlement
among NRG, GenOn, and certain holders of senior unsecured notes of GenOn Americas
Generations and GenOn, and certain of GenOn's direct and indirect subsidiaries
The CVSR Holdco interest, which was sold to NRG Yield, Inc. on September 1, 2016
Securities Industry and Financial Markets Association
Spent Nuclear Fuel
Sulfur Dioxide
NRG's South Central business, which owns and operates a 3,555 MW portfolio of generation
assets consisting of 225 MW Bayou Cove, 430 MW Big Cajun-I, 1,461 MW Big Cajun-II,
1,263 MW Cottonwood and 176 MW Sterlington, and serves a customer base of cooperatives,
municipalities and regional utilities under load contracts.
Solar Power Partners
Standard & Poor's
South Texas Project — nuclear generating facility located near Bay City, Texas in which
NRG owns a 44% interest
South Texas Project Nuclear Operating Company
The Tax Cuts and Jobs Act of 2017
Telephone Consumer Protection Act
Prior to June 30, 2016, the Company's $2.0 billion term loan facility due 2018.
Texas Genco LLC
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
Transportation Services Agreement
Total Shareholder Return
Tennessee Valley Authority
Texas Westmoreland Coal Co.
Terawatt Hour
United Nations Framework Convention on Climate Change
University of Pittsburgh Medical Center
United States of America
U.S. Department of Energy
8
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
VCP
VIE
WECC
WST
Value at Risk
Voluntary Clean-Up Program
Variable Interest Entity
Western Electricity Coordinating Council
Washington-St. Tammany Electric Cooperative, Inc.
Yield Operating
NRG Yield Operating LLC
9
PART I
Transformation Plan
Item 1 — Business
General
NRG Energy, Inc., or NRG or the Company, is a leading integrated power company built on the strength of a 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 30,000 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 power to its customers
in the markets served by the Company, while positioning the Company to provide fully integrated solutions to the end-use energy
consumer. This strategy is intended to enable the Company to create and maintain growth at reasonable margins while de-risking
the Company in terms of reduced and mitigated exposure to 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) deploying innovative and renewable 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 reducing consolidated
debt and pursuing selective acquisitions, joint ventures, divestitures and investments.
NRG is in the process of executing its Transformation Plan, which is designed to significantly strengthen earnings and
cost competitiveness, lower risk and volatility, and create significant shareholder value. The Company expects to fully implement
the Transformation Plan by the end of 2020 with significant completion by the end of 2018. The three-part, three-year plan is
comprised of the following targets and the Company's progress toward achieving such targets are as follows:
Operations and cost excellence
Cost savings and margin enhancement of $1,065 million recurring, which consists of $590 million of annual cost savings, a
$215 million net margin enhancement program, $50 million annual reduction in maintenance capital expenditures, and $210
million in permanent selling, general and administrative expense reduction associated with asset sales.
• During the year ended December 31, 2017, the Company realized annual cost savings of $150 million.
Portfolio optimization
Targeting up to $3.2 billion of asset sale cash proceeds, including divestitures of 6 GWs of conventional generation and
businesses (excluding GenOn) and the expected monetization of 100% of its interest in NRG Yield, Inc. and its renewables
platform.
• On February 6, 2018, NRG announced agreements to sell (i) NRG's full ownership interest in NRG Yield, Inc. and NRG's
renewables platform, a 3,440 MW portfolio, for cash of $1.375 billion, subject to certain adjustments; and (ii) NRG's
South Central business, a 3,555 MW portfolio of generation assets, for cash of $1.0 billion, subject to certain adjustments.
The transactions are subject to customary closing conditions and are expected to close in the second half of 2018.
• Also on February 6, 2018, NRG entered into agreements with NRG Yield, Inc. to sell Carlsbad Energy Center, a 527
MW natural gas fired project, for cash of $365 million, subject to certain adjustments, and Buckthorn Solar, a 154 MW
solar facility, for cash of $42 million, subject to certain adjustments.
• On February 23, 2018, NRG entered into an agreement to sell BETM for $70 million. The transaction is subject to
customary closing conditions and is expected to close in the second half of 2018.
• In 2017, NRG executed asset sales of 322 MW for aggregate cash of $150 million, which includes sales to NRG Yield,
Inc. and sale of Minnesota wind projects to third parties.
Capital structure and allocation enhancement
A prioritized capital allocation strategy that targets a reduction in consolidated debt from approximately $19.5 billion ($18
billion net debt) to approximately $6.5 billion ($6 billion net debt). Following the completion of the contemplated asset sales,
the Company expects approximately $5.3 billion in excess cash to be available for allocation through 2020, after achieving its
targeted 3.0x net debt / Adjusted EBITDA corporate credit ratio.
• During 2017, NRG reduced its net corporate debt by $604 million.
• Expected reduction in non-recourse debt related to the sale of NRG's ownership in NRG Yield, Inc. and the NRG
renewables platform and the sales of Carlsbad Energy Center and Buckthorn Solar, which represented $7.1 billion as of
December 31, 2017.
Working Capital and Costs to Achieve
The Company expects to realize (i) $370 million of non-recurring working capital improvements through 2020, and (ii)
approximately $290 million one-time costs to achieve.
• During 2017, NRG realized $221 million of working capital improvements and $44 million of one-time costs to achieve.
10
11
Business Overview
As of December 31, 2017, the Company’s core businesses include (i) wholesale conventional generation, (ii) retail electricity
for residential and commercial, including personal power solutions and Business Solutions, which includes C&I customers and
other distributed and reliability products (included in the Retail segment, effective in January 2017), (iii) contracted generation
owned by NRG Yield, Inc. (included in the NRG Yield segment) and (iv) 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). On June 14, 2017, NRG deconsolidated GenOn for financial reporting purposes as a result of the GenOn bankruptcy
filings.
Generation
The Company’s wholesale power generation business includes 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 a diversified power generation portfolio, with approximately 28,000 MW of fossil fuel and nuclear generation
capacity at 51 plants as of December 31, 2017. 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, 2017, less than 25% of the Company's consolidated operating revenues
were derived from coal-fired operating assets. As noted above, the Company expects to sell its 3,555 MW South Central business
in the second half of 2018.
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, 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
major metropolitan areas. The Company believes that its extensive generation portfolio provides asset optimization opportunities.
The Company currently has over 500 MW targeted for repowering initiatives, all of which are under development or construction.
In addition, the Company evaluates opportunities for new generation, on both a merchant and contracted basis.
Retail
Retail provides energy and related services to residential, industrial and commercial consumers through various brands
and sales channels across the U.S. In 2017, Retail delivered approximately 63 TWhs and served approximately 2.9 million
customers. Retail's results make it one of the largest competitive energy retailers in the U.S. The majority of Retail's sales come
in the competitive retail energy markets of Texas, Pennsylvania, Connecticut, Delaware, Illinois, Maryland, Massachusetts, New
Jersey, New York and Ohio, as well as the District of Columbia. Retail's brands collectively are the largest providers of electricity
in Texas.
Residential and small commercial (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 includes demand response, commodity sales, energy
efficiency and energy management solutions. An integrated provider of supply and distributed energy resources, Business
Solutions focuses on 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
and advisory services. 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. In 2017, Business Solutions delivered
approximately 21 TWhs of electricity and managed approximately 1,500 MWs of demand response positions across its portfolio.
Renewables and NRG Yield
As described above, NRG expects to sell its Renewables operating and development platform and its full ownership interest
in NRG Yield, Inc. in the second half of 2018. The following description reflects the historical view of these businesses as a
part of NRG’s business strategy through its announcement of the Transformation Plan in 2017.
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. In 2017, the Company acquired 209 MW of utility scale solar and wind
projects and 82 MW of distributed generation and community solar projects that are currently under development or in operation
across three 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 27 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 group self-performs plant operations on 2,689 MW of the consolidated fleet of assets owned by NRG and NRG
Yield, Inc. and 224 MW of 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,
2017, the Company held a backlog of in-construction, contracted and awarded projects of 1,500 MW, and a pipeline of 5,742
MW across the utility, community solar and distributed solar renewables markets.
The renewables business also competes for new generation opportunities through both RFPs and bilateral solicitations.
The renewables business selects markets and projects 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 that has historically served 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, 2017, NRG owns a 55.1% voting interest in the outstanding common stock of NRG
Yield, Inc. and receives distributions from NRG Yield LLC through its 46.3% ownership of Class B and Class D units. NRG
Yield, Inc.’s contracted generation portfolio collectively represents 5,118 net MW as of December 31, 2017. Each of the assets
sells most 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.
12
13
GenOn Chapter 11 Cases
NRG Operations
The NRG businesses described above are 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, net capacity and retail capabilities as of December 31, 2017:
As disclosed in Item 15 - Note 1, Nature of Business, to the Consolidated Financial Statements, on June 14, 2017, or the
Petition Date, GenOn, along with GenOn Americas Generation and certain of their directly and indirectly-owned subsidiaries,
or collectively the GenOn Entities, filed voluntary petitions for relief under Chapter 11, or the Chapter 11 Cases, of the U.S.
Bankruptcy Code, or the Bankruptcy Code, in the U.S. Bankruptcy Court for the Southern District of Texas, Houston Division,
or the Bankruptcy Court. GenOn Mid-Atlantic, as well as its consolidated subsidiaries, REMA and certain other subsidiaries,
did not file for relief under Chapter 11.
As a result of the bankruptcy filings and beginning on June 14, 2017, GenOn and its subsidiaries were deconsolidated
from NRG’s consolidated financial statements. NRG recorded its investment in GenOn under the cost method with an estimated
fair value of zero. NRG determined that this disposal of GenOn and its subsidiaries is a discontinued operation; and, accordingly,
the financial information for all historical periods has been recast to reflect GenOn as a discontinued operation. In connection
with the disposal, NRG recorded a loss on deconsolidation of $208 million during the quarter ended June 30, 2017, which is
included within the total loss from discontinued operations of $789 million for the year ended December 31, 2017. See Note 3,
Discontinued Operations, Acquisitions and Dispositions, for more information. In addition, upon GenOn's emergence from
bankruptcy, the Company will recognize an estimated $9.5 billion worthless stock deduction for tax purposes.
On June 29, 2017, the GenOn Entities filed the initial plan of reorganization and the disclosure statement with the Bankruptcy
Court consistent with the Restructuring Support Agreement. On September 18, 2017 and October 2, 2017, the GenOn Entities
filed amendments to the plan of reorganization and the disclosure statement which primarily provided the GenOn Entities with
the flexibility to complete sales of certain assets pursuant to the amended plan of reorganization and removed the GenOn Entities'
requirement to conduct a rights offering in connection with the GenOn Entities' exit financing.
On October 31, 2017, the GenOn Entities announced that they entered into a Consent Agreement with certain holders of
GenOn’s Senior Notes and GenOn Americas Generation's Senior Notes, collectively, the Consenting Holders, whereby the
GenOn Entities and the Consenting Holders agreed to extend the milestones in the Restructuring Support Agreement, by which
the plan of reorganization must become effective, or the Effective Date. Specifically, the Consent Agreement extended the
Effective Date milestone to June 30, 2018 or September 30, 2018, if regulatory approvals are still pending, or the Extended
Effective Dates.
On December 12, 2017, the Bankruptcy Court entered an order confirming the plan of reorganization, and effective
December 12, 2017, GenOn and NRG entered into agreements concerning (i) timeline and transition, (ii) cooperation and co-
development matters, (iii) post-employment and retiree health and welfare benefits and pension benefits, (iv) tax matters, and
(v) intercompany balances, consistent with the Restructuring Support Agreement, which among other things, provide for the
transition of GenOn to a standalone enterprise, resolution of substantial intercompany claims between GenOn and NRG, and
the allocation of certain costs and liabilities between GenOn and NRG. The principal terms of these agreements are described
further in Note 3, Discontinued Operations, Acquisitions and Dispositions. On December 12, 2017, the Bankruptcy Court also
entered an order giving effect to the Consent Agreement.
14
15
The following table summarizes NRG's global generation portfolio as of December 31, 2017:
Commercial Operations Overview
Generation Type
Natural gas(g)
Coal
Oil
Nuclear
Wind(h)
Utility Scale Solar
Distributed Solar
Total generation capacity(i)
Capacity attributable to
noncontrolling interest(i)
Total net generation capacity
Global Generation Portfolio(a)(b)
(In MW)
Generation
Gulf Coast(j) East/West (c)
4,939
7,464
Renewables (d)(k)
—
NRG Yield (e)(k) Other(f)(k)
—
1,878
5,114
—
1,136
—
—
—
3,870
3,642
—
—
—
—
13,714
12,451
—
13,714
—
12,451
—
—
—
648
738
179
1,565
(685)
880
—
190
—
2,206
921
52
5,247
(2,359)
2,888
—
—
—
—
—
114
114
—
114
Total Global
14,281
8,984
3,832
1,136
2,854
1,659
345
33,091
(3,044)
30,047
(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) GenOn, which represented 16,423 MW of global generation at December 31, 2016, was deconsolidated from NRG for financial reporting purposes on
June 14, 2017.
(c) Includes International.
(d) Includes Distributed Solar capacity from assets held by DGPV Holdco 1, DGPV Holdco 2 and DGPV Holdco 3.
(e) Does not include NRG Yield, Inc.'s thermal converted (MWt) capacity, which is part of the NRG Yield operating segment.
(f) The Distributed Solar figure within "Other" 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.
(g) Natural gas generation does not include 51 MW related to the Miramar and El Cajon sites which were part of the San Diego Combustion Turbines and
retired on January 1, 2017, 106 MW related to Encina Unit 1 which was deactivated on March 31, 2017 and 371 MWs related to Greens Bayou 5 which
was mothballed on May 29, 2017 following ERCOT's termination of the RMR agreement. Greens Bayou 5 was retired in January 2018.
(h) In 2017 and 2018, NRG sold 111 and 10 MWs, respectively, to third parties related to certain Minnesota wind assets.
(i) 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 5,241 MWs.
(j) On February 6, 2018, NRG announced the sale of its South Central business, which owns and operates a 3,555 MW portfolio of generation assets in Gulf
Coast. NRG will lease back the 1,263 MW Cottonwood facility.
(k) On February 6, 2018, NRG announced the sale of its full ownership in NRG Yield, Inc. and its Renewables operating and development platform, which
represents 3,440 MW.
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. In addition,
NRG's capacity revenues not only enhance the reliability of future cash flows but are not correlated to natural gas prices. As of
December 31, 2017, the Company had purchased fuel forward under fixed price contracts, with contractually-specified price
escalators, for approximately 41% of its expected coal requirement from 2018 to 2021. The Company enters into additional
hedges when it believes market conditions are favorable.
The Company also has the advantage of being able to supply its retail businesses with its own generation, which can reduce
the need to sell and buy power from other institutions and intermediaries, resulting in lower transaction costs and credit exposures.
This combination of generation and retail allows for a reduction in actual and contingent collateral, through offsetting transactions
and by reducing the need to hedge the retail power supply through third parties.
The generation and retail combination also provides stability in cash flows, as changes in commodity prices generally have
offsetting impacts between the two businesses. The offsetting nature of generation and retail, in relation to changes in market
prices, is an integral part of NRG's goal of providing a reliable source of future cash flow for the Company.
When developing new renewable and conventional power generation facilities, NRG typically secures long-term PPAs,
which insulate the Company from commodity market volatility and provide future cash flow stability. These PPAs are typically
contracted with high credit quality local utilities and typically have durations from 10 years to as much as 25 years.
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.
In addition to power sales and hedging arrangements, NRG trades electric power, natural gas and related commodity and
financial products, including forwards, futures, options and swaps. 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, 2017, and through
2021 for the Company's Gulf Coast region:
Gulf Coast
2018
2019
2020
2021
Annual
Average for
2018-2021
Net Coal and Nuclear Capacity (MW) (a)
Forecasted Coal and Nuclear Capacity (MW) (b)
Total Coal and Nuclear Sales (GWh) (c)
Percentage Coal and Nuclear Capacity Sold Forward (d)
Total Forward Hedged Revenues (e)
Weighted Average Hedged Price ($ per MWh) (e)
Average Equivalent Natural Gas Price ($ per MMBtu) (e)
Gross Margin Sensitivities
(Dollars in millions unless otherwise stated)
6,250
4,558
33,394
6,250
4,402
8,203
6,250
4,303
7,348
6,250
4,114
7,977
6,250
4,344
14,231
84%
21%
19%
22%
37%
$ 1,399
$ 41.90
$ 3.17
$
$
$
$
422
$ 399
$ 429
51.47
$54.36
$53.74
4.47
$ 4.79
$ 5.01
134
$ 136
$ 138
$
$
$
$
$
$
$
—
—
—
—
—
—
—
Gas Price Sensitivity Up $0.50/MMBtu on Coal and Nuclear Units
$
5
Gas Price Sensitivity Down $0.50/MMBtu on Coal and Nuclear Units
$ — $
(150)
$ (148)
$ (126)
Heat Rate Sensitivity Up 1 MMBtu/MWh on Coal and Nuclear Units
Heat Rate Sensitivity Down 1 MMBtu/MWh on Coal and Nuclear Units
$
$
57
(38)
$
$
90
(74)
$
$
94
(78)
$
$
96
(79)
(a) Net coal and nuclear capacity represents nominal summer net MW capacity of power generated as adjusted for the Company's current 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, 2017, which is then divided by number of hours in a
(c)
given year to arrive at MW capacity. The dispatch takes into account planned and unplanned outage assumptions.
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, 2017, 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
17
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, 2017 and through 2021 for the East/West
region:
East/West
2018
2019
2020
2021
Annual
Average for
2018-2021
Net Coal Capacity (MW) (a)
Forecasted Coal Capacity (MW) (b)
Total Coal Sales (GWh) (c)
Percentage Coal Capacity Sold Forward (d)
Total Forward Hedged Revenues (e)
Weighted Average Hedged Price ($ per MWh) (e)
Average Equivalent Natural Gas Price ($ per MMBtu) (e)
Gross Margin Sensitivities
Gas Price Sensitivity Up $0.50/MMBtu on Coal Units
Gas Price Sensitivity Down $0.50/MMBtu on Coal Units
Heat Rate Sensitivity Up 1 MMBtu/MWh on Coal Units
Heat Rate Sensitivity Down 1 MMBtu/MWh on Coal Units
(Dollars in millions unless otherwise stated)
3,267
1,579
12,520
3,267
1,456
1,521
3,267
1,258
644
3,267
881
46
3,267
1,294
3,683
91%
12%
6%
1%
27%
$
408
$
46
$
20
$
1
$
$ 32.60
$ 30.57
$ 30.68
$ — $
$
2.76
$
2.84
$
2.73
$ — $
$
$
$
$
47
(36)
31
(23)
$
$
$
$
113
(96)
66
(59)
$
$
$
$
114
(91)
64
(56)
$
$
$
$
118
(71)
66
(49)
$
$
$
$
—
—
—
—
—
—
—
(a) Net coal capacity represents nominal summer net MW capacity of power generated as adjusted for the Company's current 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, 2017, 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, 2017, 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.
• Resource adequacy and bilateral contracts — In California, there is a resource adequacy requirement that is primarily
satisfied through bilateral contracts. Such bilateral contracts are typically short-term resource adequacy contracts. When
bilateral contracting does not satisfy the resource adequacy need, such shortfalls can be addressed through procurement
tools administered by the CAISO, including the capacity procurement mechanism or reliability must-run contracts. In
addition, NRG earns demand payments from its long-term full-requirements load contracts with nine Louisiana
distribution cooperatives, which expire in 2025. 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.
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 businesses and fuel products used.
Coal — The Company believes it is adequately hedged, using forward coal supply agreements, for its domestic coal
consumption for 2018. NRG actively manages its coal requirements based on forecasted generation, market volatility and its
inventory on site. As of December 31, 2017, NRG had purchased forward contracts to provide fuel for approximately 41% of
the Company's expected requirements from 2018 through 2021, including expected coal inventory draw down. NRG purchased
approximately 21 million tons of coal in 2017, almost all of which was Powder River Basin coal. 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 4 years.
The following table shows the percentage of the Company's coal requirements from 2018 through 2021 that have been
purchased forward as of December 31, 2017:
2018
2019
2020
2021
(a)
Includes expected coal inventory draw down.
Percentage of
Company's
Requirement (a)
97%
40%
26%
—%
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 original 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. Since the operating license was renewed for another 20 years in September 2017, STPNOC
has begun to review a second phase of fuel purchasing.
Retail Operations
In 2017, 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 five
years while industrial contracts are often between one year and five years in length. In 2017, NRG's retail businesses sold
approximately 63 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
19
Operational Statistics
The generation performance by region for the three years ended December 31, 2017, 2016 and 2015, is shown below:
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 global power generation portfolio, including leased
facilities and those accounted for through equity method investments, for the years ended December 31, 2017 and 2016:
Year Ended December 31, 2017
Fossil and Nuclear Plants
Net Generation
Net Owned
Capacity (MW)
(MWh)
(In thousands) (b)
Annual Equivalent
Availability Factor
Average Net Heat
Rate BTU/kWh
Net Capacity
Factor
Generation
Gulf Coast
East/West
Renewables
NRG Yield (a)
Generation
Gulf Coast
East/West
Renewables
NRG Yield (a)
13,714
12,451
1,565
5,247
49,573
13,373
3,836
10,686
89.5%
85.4
94.7
95.5
10,106
10,757
—
8,938
38.9%
12.2
38.2
21.4
Year Ended December 31, 2016
Fossil and Nuclear Plants
Net Generation
Net Owned
Capacity (MW)
(MWh)
(In thousands) (b)
Annual Equivalent
Availability Factor
Average Net Heat
Rate BTU/kWh
Net Capacity
Factor
14,085
12,519
1,788
3,310
47,827
17,114
3,827
11,230
88.2%
78.3
96.9
96.6
10,028
10,258
—
8,848
38.6%
15.7
35.3
22.6
Generation
Gulf Coast
Coal
Gas
Nuclear (a)
Total Gulf Coast
East/West
Coal
Oil
Gas
Total East/West
Renewables
Solar
Wind
Total Renewables
NRG Yield
Solar
Wind
Gas and Dual-Fuel (b)
Total NRG Yield
2017
Net Generation
2016
(In thousands of MWh)
2015
28,622
11,442
9,509
49,573
8,407
319
4,647
13,373
1,740
2,096
3,836
1,248
5,597
3,841
10,686
25,197
13,071
9,559
47,827
11,096
318
5,700
17,114
1,634
2,193
3,827
1,281
6,010
3,939
11,230
29,301
16,288
8,573
54,162
19,155
567
4,909
24,631
1,027
2,281
3,308
1,332
4,479
4,731
10,542
(a) MWh information reflects the Company's undivided interest in total MWh generated by STP.
(b) Gas and Dual-Fuel includes thermal heating and chilled water generation as well as assets contracted under tolling agreements.
(a) NRG Yield includes thermal generation.
(b) Net generation excludes equity method investments.
20
21
Segment Review
The Company's segment structure reflects how management currently makes financial decisions and allocates resources.
Effective January 2017, the Company's businesses are segregated as follows: Generation , which includes generation, international
and BETM; Retail which includes Mass customers and Business Solutions, which includes C&I customers and other distributed
and reliability products; Renewables, which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and
corporate activities. 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.
During 2017, NRG Yield acquired several projects totaling 555 MW for cash consideration of approximately $245 million
from NRG. These acquisitions were accounted for as transfers of entities under common control and accordingly, all historical
periods have been recast to reflect this change.
On June 14, 2017, NRG deconsolidated GenOn for financial reporting purposes. The financial information for all historical
periods have been recast to present GenOn as discontinued operations within the corporate segment.
Revenues
The following table contains a summary of NRG's operating revenues by segment for the years ended December 31, 2017,
2016 and 2015, 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 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.
Generation
Retail
Renewables
NRG Yield
Corporate and Eliminations (b)
Total
Year Ended December 31, 2017
Energy
Revenues
Capacity
Revenues
Retail
Revenues
Mark-to-
Market
Activities
Contract
Amortization
Other
Revenues(a)
Total
Operating
Revenues(b)
$
$ 2,636
—
359
554
(1,088)
851
—
—
346
(11)
$
— $
6,385
—
—
3
(In millions)
37
$
(4)
(12)
—
218
$ 2,461
$ 1,186
$
6,388
$
239
$
$
14
(1)
—
(69)
—
(56) $
235
—
77
178
(79)
411
$
3,773
6,380
424
1,009
(957)
$ 10,629
(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, 2016
Energy
Revenues
Capacity
Revenues
Retail
Revenues
Mark-to-
Market
Activities
Contract
Amortization
Other
Revenues(c)
Total
Operating
Revenues(d)
3,833
Generation
6,335
Retail
406
Renewables
1,035
NRG Yield
Corporate and Eliminations (d)
(1,097)
$ 10,512
Total
(c) Primarily consists of revenues generated by the Thermal business (NRG Yield segment), operation and maintenance revenues and unrealized trading
$ 3,171
—
369
582
(991)
$ 3,131
891
—
—
345
(11)
$ 1,225
15
(1)
(1)
(69)
—
(56) $
6,336
—
—
21
6,357
322
—
44
177
(46)
497
— $
$
$
$
$
$
$
(In millions)
(566) $
—
(6)
—
(70)
(642) $
activities, primarily at BETM (Generation segment).
(d) Energy revenues include inter-segment sales primarily between Generation and Retail.
Year Ended December 31, 2015
Energy
Revenues
Capacity
Revenues
Retail
Revenues(f)
Mark-to-
Market
Activities
Contract
Amortization
Other
Revenues(e)
Total
Operating
Revenues(f)
5,179
Generation
6,913
Retail
383
Renewables
968
NRG Yield
Corporate and Eliminations(f)
(1,115)
$ 12,328
Total
(e) Primarily consists of revenues generated by the Thermal business (NRG Yield segment), operation and maintenance revenues and unrealized trading
$ 4,072
—
356
495
(1,056)
$ 3,867
$ 1,027
—
—
341
(7)
$ 1,361
15
(1)
—
(54)
—
(40) $
6,910
—
—
(43)
6,867
207
—
30
188
(18)
407
— $
$
$
$
$
$
(In millions)
(142) $
4
(3)
(2)
9
(134) $
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 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 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
23
East/West
Regulatory Matters
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, while NYISO uses
a month-ahead capacity auction. 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.
In the West region, 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.
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 NRG's utility scale renewable
generating facilities. There are examples of states increasing their RPS from initially stated levels, such as California’s 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.
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 Energy Regulation
FERC
FERC 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.
Derivatives Regulatory Reforms
In the U.S., the CFTC regulates the trading of swaps, futures and many commodities under the Commodity Exchange Act,
or CEA. In recent years, 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.
Department of Energy's Proposed Grid Resiliency Pricing Rule — On September 29, 2017, the Department of Energy
issued a proposed rulemaking titled the "Grid Resiliency Pricing Rule." The rulemaking proposed that FERC take action to
reform the ISO/RTO markets to value certain reliability and resiliency attributes of electric generation resources. On October
23, 2017, NRG filed comments encouraging FERC to act expeditiously to modernize energy and capacity markets in a manner
compatible with robust competitive markets. On January 8, 2018, FERC terminated the proposed rulemaking and opened a new
rulemaking asking each ISO/RTO to address specific questions focused on grid resilience.
State Energy Regulation
In Texas, NRG's operations within the ERCOT footprint are not subject to rate regulation by FERC, because they operate
solely within the ERCOT market. 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.
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 businesses depends on state competition and other policies.
24
25
State Out-Of-Market Subsidy Proposals — Certain states in the areas of the country in which NRG operates, including
New Jersey, Ohio and Pennsylvania have considered but have not enacted proposals to provide out-of-market subsidy payments
to potentially uneconomic nuclear and fossil generating units. NRG has opposed efforts to provide out-of-market subsidies,
and intends to continue opposing them in the future.
Nuclear Operations
NRG South Texas LP owns 44% of a joint undivided interest in STP. The other owners of STP are 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, recently extended
until 2047 and 2048, respectively, 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.
If 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.
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.
Gulf Coast
MISO
Revisions to MISO Capacity Construct — On February 28, 2018, FERC issued two orders on MISO’s capacity market
design, which together, re-affirm MISO’s existing capacity market structure. FERC also held that, even though there was a
period of time between where MISO’s capacity market structure may not have just and reasonable, that FERC exercised its
remedial authority not to rerun past auctions. The Company has 30 days to seek an administrative rehearing with FERC. The
eventual outcome of this proceeding will affect capacity prices in MISO and the incentive for generators in MISO to sell capacity
into neighboring markets.
East/West
FERC’s Fast-Start Pricing Dockets — On December 28, 2017, notices were published regarding FERC’s initiation of FPA
section 206 proceedings for the NYISO, PJM, and SPP to investigate these ISO pricing practices for fast-start generating resources.
FERC found that the practices of each ISO regarding the pricing of fast-start resources may be unjust and unreasonable because
the practices do not allow prices to reflect the marginal cost of serving load. FERC also terminated its generic rulemaking into
these issues. The proceeding is ongoing. The outcome of this proceeding could affect price formation in the respective energy
markets.
PJM
Minimum Offer Price Rule Exemption Appeal — On July 7, 2017, the D.C. Circuit vacated a FERC order from 2013 related
to an exemption to the Minimum Offer Price Rule, or MOPR, and remanded the issue back to FERC. On October 23, 2017,
PJM re-filed its initial 2012 MOPR. On December 8, 2017, FERC rejected PJM's filing and directed PJM to submit a compliance
filing reinstating the MOPR in effect prior to PJM's December 2012 filing. PJM submitted a compliance filing modifying certain
PJM tariff sections, retaining the unit-specific exception, which FERC has accepted.
Generators’ Complaint on Existing Generation MOPR — On January 9, 2017, NRG, its trade association and other
generators 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 filing amends the March 21, 2016 complaint filed by NRG and other
companies related to ratepayer-funded subsidies approved by the PUCO. The national trade association sought expedited
treatment to implement countermeasures to protect consumers and wholesale power markets from the negative effects of out-
of-market subsidies, like the Zero Emission Credit. The complaint is pending at FERC.
2020/2021 PJM Auction Results — On May 23, 2017, PJM announced the results of its 2020/2021 Base Residual Auction.
NRG cleared approximately 3,992 MW of Capacity Performance product. NRG’s expected capacity revenues from the Base
Residual Auction for the 2020/2021 delivery year are approximately $268 million.
The table below provides a detailed description of NRG’s 2020/2021 base residual auction results from May 23, 2017:
Zone
Cleared Capacity (MW)(a)
Price ($/MW-day)
Capacity Performance Product
COMED
EMAAC
MAAC
Total
3,315
519
158
3,992
$
$
$
188.12
187.87
86.04
(a) Includes imports. Does not include capacity sold by NRG Curtailment Solutions.
PJM Seasonal Capacity Proceeding — On November 17, 2016, PJM proposed to allow winter- and summer-peaking
capacity resources to “aggregate” their seasonal capacity into an annual capacity product eligible to participate as Capacity
Performance resources. 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. On March 21, 2017, FERC issued a decision accepting PJM's
seasonal capacity aggregation filing pursuant to FERC staff's delegated authority, since FERC did not have a quorum at the time.
On February 23, 2018, FERC re-affirmed its prior order. Rehearings are pending at 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.
26
27
Complaints Regarding Pseudo-Ties for Capacity — On April 6, 2017, Potomac Economics, the market monitor for MISO
and NYISO, filed a complaint against PJM regarding the participation of external capacity resources in PJM’s auction. Currently,
external resources must enter into a pseudo-tie agreement in order to sell capacity into PJM. The complaint alleges that the
pseudo-tie requirement is causing market inefficiencies in PJM, New York and MISO and suggests a new protocol for
incorporating external resources into PJM’s markets. In addition, other market participants have filed separate complaints at
FERC against MISO or PJM, respectively, for issues resulting from pseudo-tied generators. The complainants argue that the
generation owners with pseudo-ties from MISO to PJM are receiving double-charges for congestion. The outcome could impact
the PJM, NYISO and MISO capacity markets.
Midwest Generation Reactive Power Compensation — On June 21, 2016, FERC issued an order directing Midwest
Generation 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 Midwest Generation 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. FERC
also referred this matter to FERC's Office of Enforcement. On June 30, 2016, Midwest Generation filed a revised tariff, and on
July 22, 2016, Midwest Generation made a compliance filing as ordered by FERC. On October 13, 2016, FERC found that
Midwest Generation should only be liable for refunds that accrued after bankruptcy on April 1, 2014 through June 30, 2016.
On November 16, 2017, Midwest Generation filed its Offer of Settlement, which was approved by FERC on February 22, 2018.
In addition, FERC's Office of Enforcement has closed the investigation into Midwest Generation without further action.
New England
Competitive Auctions with Sponsored Resources Proposal (CASPR) — On January 8, 2018, ISO-NE filed the CASPR
proposal which attempts to accommodate state sponsored resources while maintaining competitive market pricing. On January
29, 2018, NRG protested certain aspects of the proposal and also supported ISO-NE’s beginning attempts to address state
sponsored resources entering the capacity market. The outcome of this proceeding will potentially affect future capacity market
prices.
Renewable Technology Resource (RTR) Exemption — In 2014, FERC approved a package of revisions that included a
renewables exemption called the RTR Exemption. After FERC denied rehearing, the case was appealed to the D.C. Circuit.
After a voluntary remand motion, the Court remanded the case back to FERC. In 2016, FERC issued an order reaffirming its
decision. In 2017, a group of generators, including NRG, filed a petition for review with the D.C. Circuit. Briefing is complete.
Oral argument is scheduled for April 13, 2018.
Challenge to ISO-NE’s Capacity Carry Forward Rule — On February 2, 2018, the D.C. Circuit remanded a FERC order
regarding how generators that previously received a seven-year “price lock” should be priced in future auctions, known as the
Capacity Carry Forward Rule. The price-lock mechanism permits qualified new resources that clear the auction to receive their
first-year clearing price for seven years. Because the underlying orders focused on the implementation of the Capacity Carry
Forward Rule, this remand does not implicate the validity of the underlying price-lock. Because several auctions have been
held under the existing rules, any subsequent order from FERC could affect future capacity prices in New England, as well as
affect the price that non-price locked resources could receive from prior capacity auction.
2021/2022 ISO-NE Auction Results — On February 6, 2018, ISO-NE announced the results of its 2021/2022 forward
capacity auction. NRG cleared 1,529 MW at $4.631 kW-month providing expected annualized capacity revenues of $85 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 $7.03 kW-month for the 2021/2022 deliverability year, are excluded from these results.
Massachusetts GHG Regulations — On September 11, 2017, multiple generators, including GenOn Energy, Inc. and the
New England Power Generators Association, or NEPGA, filed complaints regarding the Massachusetts GHG regulations with
the Superior Court in Massachusetts. The complaint alleges that the final regulation does not demonstrate a lowering of emissions
and that the regulation violates the state’s Global Warming Solutions Act law. On January 30, 2018, the Massachusetts Supreme
Judicial Court transferred the superior court cases to the Supreme Judicial Court for Suffolk County. At the same time, the Court
stayed two pending appeals of siting certificates, one of which is the certificate of NRG’s Canal 3 development. The outcome
of the matter may affect generators’ abilities to run their plants without violating environmental regulations.
Northern Pass Siting Application — On February 1, 2018, the New Hampshire Site Evaluation Committee denied the
application for Northern Pass to cross the state with a 160-mile transmission line from Quebec into southern New Hampshire.
The Northern Pass transmission line project had previously been awarded a contract by the State of Massachusetts, which is
now in doubt. The addition of 1,000 MW of additional Canadian hydropower associated with Northern Pass would have affected
energy and capacity prices.
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. The
PER adjustment reduces capacity payments on days where energy prices exceed a pre-defined level, known as the "PER strike
price." On January 9, 2017, FERC granted NEPGA’s complaint requiring a change to the methodology used to calculate the
PER strike price. FERC also directed the parties to determine any refunds for PER paid between September 30, 2016 and May
31, 2018. On July 26, 2017, NEPGA filed settlement documents at FERC, which NRG supported. On February 20, 2018, FERC
accepted the settlement and directed ISO-NE to submit a compliance filing setting out the PER calculation.
New York
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 be mitigated. 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
placed a price cap on energy supply offers and required many retail providers to seek affirmative consent from certain retail
customers. Various parties have challenged the NYPSC’s ability to regulate rates charged by competitive suppliers in New York
state court. In conjunction with the court challenges, the NYPSC noticed both an evidentiary and a collaborative track to address
the functioning of the competitive retail markets. An administrative hearing commenced on November 29, 2017 as part of the
evidentiary track, which is ongoing. The outcome of the evidentiary and collaborative processes, combined with the outcome
of the appeal of the Reset Order, could affect the viability of the New York retail energy market.
CAISO
Puente Power Project — On October 5, 2017, the California Energy Commission, or CEC, the agency responsible for
permitting the Puente Power Project, issued a statement on behalf of the committee of two Commissioners overseeing the
permitting process stating their intention to issue a proposed decision that would deny a permit for the Puente Power Project.
On October 16, 2017, NRG filed a motion to suspend the permitting proceeding for at least six months, which was granted on
November 3, 2017. During the six month suspension period, which could be extended, NRG will evaluate the progress of a
procurement process initiated by SCE to replace the Puente Power Project.
Environmental Matters
NRG is subject to numerous 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. Federal and state environmental laws historically have become more stringent over time. Future laws may require
the addition of emissions controls or other environmental controls or impose restrictions on our operations, which could affect
the Company's operations. Complying with environmental laws often involves significant capital and operating expenses, as
well as occasionally curtailing operations. 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 that may affect the Company are under review by the EPA, including ESPS for GHGs, ash disposal
requirements, NAAQS revisions and implementation and effluent limitation guidelines. NRG will evaluate the impact of these
regulations as they are revised but cannot fully predict the impact of each until anticipated legal challenges are resolved.
Air
The CAA and the resulting regulations (as well as similar state and local requirements) have the potential to affect air
emissions, operating practices and pollution control equipment required at power plants. Under the CAA, the EPA sets NAAQS
for certain pollutants including SO2, ozone, and PM2.5. Many of the Company's facilities are located in or near areas that are
classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS have become more stringent.
The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with
increasingly stringent air regulations could require the installation of additional emissions control equipment at some NRG
facilities or retiring of units if installing such controls is not economic. Significant changes to air regulatory programs affecting
the Company are described below.
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Ozone NAAQS — On October 26, 2015, the EPA promulgated a rule that reduces the ozone NAAQS to 0.070 ppm.
Challenges to this rule have been stayed at the request of the EPA so that it can evaluate the rule. If the rule is not altered by the
EPA and 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.
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 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. On April 18, 2017, the EPA asked the D.C. Circuit to postpone oral argument
that had been scheduled for May 18, 2017 because the EPA is closely reviewing the supplemental finding to determine whether
it should reconsider all or part of the rule. On April 27, 2017, the D.C. Circuit granted the EPA's request to postpone the oral
argument and hold the case in abeyance. 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 heard oral argument on the legal challenges
to the CPP in September 2016. At the EPA's request, the D.C. Circuit agreed on April 28, 2017 to hold the case in abeyance. On
October 16, 2017, the EPA proposed a rule to repeal the CPP. The Company believes the CPP is not likely to survive.
Greenhouse Gas Emissions — NRG emits CO2 and small quantities of other greenhouse gases, or GHGs, when generating
electricity at most of its facilities. The graphs presented below illustrate NRG's domestic emissions of CO2e for 2015, 2016 and
2017. A significant majority (>99%) of NRG's emission sources are subject to federal (U.S. EPA) GHG reporting requirements
programs. NRG anticipates further reductions in CO2e emissions as the Company modernizes the fleet. From 2016 to 2017, the
Company's CO2e emissions decreased from 48 million metric tons to approximately 46 million metric tons, representing a 4%
reduction year over year. The primary factor leading to the decreased emissions include reductions in fleet wide annual net
generation due to a continued market-driven shift towards increased generation from natural gas over coal. The Company's goal
is to reduce CO2e emissions by 50% by 2030, and 90% by 2050, using 2014 as a baseline.
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 and actions of the current U.S. presidential administration.
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. On September 13, 2017, the EPA granted the petition for reconsideration that the Utility Solid Waste Activities
Group filed in May 2017. 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, 2017.
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. 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.
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Nuclear Waste — The federal government's program to construct a nuclear waste repository at Yucca Mountain, Nevada
was discontinued in 2010. Since 1998, the U.S. DOE has been in default of the federal government's obligations to begin accepting
spent nuclear fuel, or SNF, and high-level radioactive waste, or HLW, under the U.S. Nuclear Waste Policy Act of 1982, or the
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 was reviewed and 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 would have imposed more stringent requirements (as individual permits were renewed)
for wastewater streams from flue gas desulfurization, or FGD, fly ash, bottom ash, and flue gas mercury control. In April 2017,
the EPA granted two petitions to reconsider the rule and also administratively stayed some of the deadlines. On September 18,
2017, the EPA promulgated a final rule that (i) postpones the compliance dates to preserve the status quo for FGD wastewater
and bottom ash transport water by two years to November 2020 until the EPA completes its next rulemaking and (ii) withdrew
the April 2017 administrative stay. The legal challenges have been suspended while the EPA reconsiders and likely modifies the
rule. Accordingly, the Company has largely eliminated its estimate of the environmental capital expenditures that would have
been required to comply with permits incorporating the revised guidelines. The Company will revisit these estimates after the
rule is revised.
Regional Environmental Developments
New Source Review — 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. 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, the Company's Closure Report 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 remediation was completed
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, 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 re-evaluated the program and published a model rule 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.
Texas Regional Haze — On October 17, 2017, the EPA promulgated a final rule creating a Texas-only SO2 cap-and-trade
program to address regional haze. The program is scheduled to begin on January 1, 2019. Several of the Company's units in
Texas will be affected by this rule. The rule has been challenged by several environmental groups in the Fifth Circuit of the U.S.
Court of Appeals.
Customers
NRG sells to a wide variety of customers. No individual customer accounted for 10% or more of NRG's total revenue in
2017. 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, 2017, NRG and its consolidated subsidiaries, including NRG Yield, Inc., had 5,940 employees,
approximately 24% of whom were covered by U.S. bargaining agreements. During 2017, 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, sustainability reports and other information
regarding the Company on the Company's website. The information posted on the Company's website is not a part of this report.
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Item 1A — Risk Factors Related to NRG Energy, Inc.
Risks Related to the Operation of NRG's Business
The GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code, and NRG is subject to the
risks and uncertainties associated with bankruptcy proceedings.
On the Petition Date, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. GenOn
Mid-Atlantic, as well as its consolidated subsidiaries, and REMA, did not file for relief under Chapter 11.
NRG is subject to a number of risks and uncertainties associated with the Chapter 11 Cases, which may lead to potential
adverse effects on NRG’s business, results of operations, or financial condition. NRG cannot assure you of the outcome of the
Chapter 11 Cases. Potential risks to NRG associated with the Chapter 11 Cases include the following:
•
•
•
the length of time the GenOn Entities will operate under the Chapter 11 proceedings and their ability to successfully
emerge, including with respect to obtaining any necessary regulatory approvals;
the ability of the GenOn Entities to consummate their plan of reorganization;
risks associated with third party motions, proceedings and litigation in the Chapter 11 proceedings, which may interfere
with the GenOn Entities’ plan of reorganization;
• NRG’s and the GenOn Entities’ ability to manage contracts that are critical to NRG’s operations, and to obtain and
maintain appropriate credit and other terms with customers, suppliers and service providers;
• NRG’s ability to attract, retain and motivate key employees;
• NRG’s ability to fund and execute its business plan;
•
the disposition or resolution of all pre-petition claims against NRG and the GenOn Entities; and
• NRG’s ability to maintain existing customers and vendor relationships and expand sales to new customers.
The Settlement Agreement may not be consummated if certain conditions are not met. If the Settlement Agreement is not
consummated, NRG may not be entitled to receive certain benefits contemplated by the Restructuring Support Agreement and
plan of reorganization.
Under the Restructuring Support Agreement to which GenOn, NRG and certain of GenOn's and GenOn Americas Generation's
senior unsecured noteholders are parties, each of them agreed to support Bankruptcy Court approval of the Settlement Agreement,
subject to conditions.
While the Bankruptcy Court approved the Settlement Agreement and confirmed the proposed plan of reorganization on
December 12, 2017, there can be no assurance that the conditions to the effectiveness of either the Settlement Agreement or plan
of reorganization will be satisfied. In addition, GenOn is entitled to terminate the Restructuring Support Agreement and consider
alternative transactions in accordance with its fiduciary duties. If the Settlement Agreement or plan of reorganization is not
consummated, NRG may not receive certain of the benefits contemplated by the Restructuring Support Agreement.
The Chapter 11 Cases may disrupt NRG's business and may materially and adversely affect NRG's operations.
NRG has attempted to minimize the adverse effect of the GenOn Entities’ Chapter 11 Cases on NRG's relationships with its
employees, suppliers, customers and other parties. Nonetheless, NRG's relationships with its employees, suppliers, customers and
other parties may be adversely impacted by negative publicity or otherwise and NRG's operations could be materially and adversely
affected. In addition, the Chapter 11 Cases could negatively affect NRG's ability to attract new employees and retain existing high
performing employees or executives, which could materially and adversely affect NRG's operations.
As a result of the Chapter 11 Cases, NRG's historical financial information will not be indicative of NRG's future financial
performance.
NRG's corporate structure will be significantly altered under any plan of reorganization. As of June 14, 2017, GenOn and
its consolidated subsidiaries were deconsolidated from NRG's financial statements. Consequently, NRG's results of operations
following the deconsolidation will not be comparable to the financial condition and results of operations reflected in NRG's
historical financial statements for periods prior to the deconsolidation.
NRG adopted and initiated the Transformation Plan. If the Transformation Plan does not achieve its expected benefits, there
could be negative impacts to NRG’s business, results of operations and financial condition.
NRG adopted and initiated the Transformation Plan, designed to significantly strengthen earnings and cost competitiveness,
lower risk and volatility, and create significant shareholder value. The three-part, three-year plan is comprised of the following
components: (i) operations and cost excellence; (ii) portfolio optimization; and (iii) capital structure and allocation enhancements.
As part of the Transformation, Plan, on February 6, 2018, NRG and GIP entered into a purchase and sale agreement for NRG
to sell its ownership in NRG Yield, Inc. and its renewables platform to GIP for cash of $1.375 billion, subject to certain adjustments.
Also on February 6, 2018, NRG and Cleco entered into a purchase and sale agreement for NRG to sell its South Central business
to Cleco for cash of $1.0 billion, subject to certain adjustments. Both of these transactions are subject to various closing conditions
and approvals.
NRG may be unable to fully implement the components of the Transformation Plan, in which case, NRG would not realize
the anticipated benefits. Alternatively, such components of the Transformation Plan, even if implemented, may not result in the
anticipated benefits to NRG’s business, results of operations and financial condition in a timely manner if at all. Further, NRG
could experience unexpected delays, business disruptions resulting from supporting these initiatives during and following
completion of these activities, decreased productivity, adverse effects on employee morale and employee turnover as a result of
such initiatives, any of which may impair NRG’s ability to achieve anticipated results or otherwise harm NRG’s business, results
of operations and financial condition.
The proposed sales of assets to GIP and Cleco could be delayed or fail to close, or otherwise cause unanticipated issues, which
could adversely affect NRG's business, results of operations and financial condition.
As described above, on February 6, 2018, NRG entered into a purchase and sale agreement with GIP pursuant to which NRG
agreed to sell its ownership interest in NRG Yield, Inc. and NRG’s Renewables platform. Also on February 6, 2018, NRG and
Cleco entered into a purchase and sale agreement for Cleco to purchase NRG's South Central business. The proposed sales are
subject to numerous closing conditions, including, among others, the receipt of certain consents and regulatory approvals. A
number of the closing conditions are outside of NRG’s control and it cannot be predicted with certainty whether all of the required
closing conditions will be satisfied or waived or if other uncertainties may arise. In addition, regulators could impose additional
requirements or obligations as conditions for their approval, which may be burdensome. If such closing conditions are not met
or additional obligations are imposed, the proposed sales may not be consummated at all or may encounter delays or other roadblocks
that are not currently anticipated. Planning and executing the proposed separation and sale of NRG’s renewables platform will
require significant time, effort, and expense, and may divert management’s attention from other aspects of NRG’s business
operations, and any delays in completion of the proposed sale may increase the amount of time, effort, and expense that NRG
devotes to the transactions, which could adversely affect NRG’s other operations. The current price of NRG’s stock may reflect
an assumption that the pending sales will occur and failure to complete the proposed sales could result in a decline in NRG’s stock
price. In addition, even if NRG completes the proposed sales, the actual impacts on NRG's business and financial results may
differ from the anticipated results.
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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;
changes in law, including judicial decisions;
• 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 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.
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;
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•
•
•
•
•
•
•
•
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:
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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 2018 and the Company also sells forward the output from its intermediate and peaking facilities when it
is 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, to manage the commodity price risks inherent in its power generation operations. These activities, although
intended to mitigate price volatility, expose the Company to other risks. When the Company sells power forward, it gives up the
opportunity to sell power at higher prices in the future, which not only may result in lost opportunity costs but also may require
the Company to post significant amounts of cash collateral or other credit support to its counterparties. The Company also relies
on counterparty performance under its hedging agreements and is exposed to the credit quality of its counterparties under those
agreements. Further, if the values of the financial contracts change in a manner that the Company does not anticipate, or if a
counterparty fails to perform under a contract, it could harm the Company's business, operating results or financial position.
NRG does not typically hedge the entire exposure of its operations against commodity price volatility. To the extent it does
not hedge against commodity price volatility, the Company's results of operations and financial position may be improved or
diminished based upon movement in commodity prices.
NRG may engage in trading activities, including the trading of power, fuel and emissions allowances that are not directly
related to the operation of the Company's generation facilities or the management of related risks. These trading activities take
place in volatile markets and some of these trades could be characterized as speculative. The Company would expect to settle
these trades financially rather than through the production of power or the delivery of fuel. This trading activity may expose the
Company to the risk of significant financial losses which could have a material adverse effect on its business and financial condition.
NRG may not have sufficient liquidity to hedge market risks effectively.
The Company is exposed to market risks through its power marketing business, which involves the sale of energy, capacity
and related products and the purchase and sale of fuel, transmission services and emission allowances. These market risks include,
among other risks, volatility arising from location and timing differences that may be associated with buying and transporting fuel,
converting fuel into energy and delivering 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 depend 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 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 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.
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:
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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;
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labor disputes;
• weather interferences;
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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 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, or 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.
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, NRG Yield, Inc., is a publicly traded corporation, 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.
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.
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 or disposition activities could involve unknown risks and may have materially adverse effects.
NRG may in the future make acquisitions or dispositions of businesses or assets or pursue other business activities, directly
or indirectly through subsidiaries, that involve a number of risks. 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. In the case of dispositions, such risks may relate to employment matters,
counterparties, regulators and other stakeholders in the disposed business, risks relating to separating the disposed assets from
NRG’s business, risks related to the management of NRG’s ongoing business, risks unknown to NRG at the time, and other
financial, legal and operational risks related to such disposition. Any such risk may result in one or more costly disputes or litigation.
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. There can also be no
assurances that NRG will realize the anticipated benefits from any such dispositions. The failure to realize the anticipated returns
or benefits from an acquisition or disposition could adversely affect NRG's results of operations, cash flows and financial condition.
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, 2017, approximately 24% 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 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.
Some emerging technologies like distributed renewable energy technologies, broad consumer adoption of electric vehicles
and energy storage devices could affect the price of energy. These emerging technologies may affect the financial viability of
utility counterparties and could have significant impacts on wholesale market prices, which could ultimately have a material
adverse effect on NRG's financial condition, results of operations and cash flows.
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 depend 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 rely 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 energy 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 energy 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.
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.
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, 2047 (Unit 1) and December 15, 2048 (Unit 2).
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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. Federal and state environmental laws generally have become more stringent over time, although this trend could slow or
pause. 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.
NRG's businesses are subject to physical, market and economic risks relating to potential effects of climate change.
Climate change is producing changes in weather and other environmental conditions, including temperature and precipitation
levels, and thus may affect 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 supply chain,
and cause them 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. NRG's commercial and residential customers
may also experience the potential physical impacts of climate change and may incur significant costs in preparing for or responding
to these efforts, including increasing the mix and resiliency of their energy solutions and supply.
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. Water risk is monitored by the risk owners (individual plant
operators) and reported to Company management upon changes with a significance threshold of 20% in water consumption and
withdrawal levels. If it is determined that a water supply risk exists that could impact projected generation levels at any plant
within the subsequent two year time frame, risk mitigation efforts are identified and economically evaluated for implementation.
Water risk regarding the impact for barge delivery is evaluated on a daily basis, with contingency plans developed as needed.
GHG regulation could increase the cost of electricity generated by fossil fuels, and such increases could reduce demand for
the power NRG generates and markets. Also, demand for NRG's energy-related services could be similarly impacted 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 mitigate climate change, could adversely
impact NRG's results of operations, financial condition and cash flows.
NRG's GHG emissions for 2017 can be found in Item 1, Business — Environmental Matters. In 2015, the EPA promulgated
the final GHG emissions rules for new and existing fossil-fuel-fired electric generating units, which have been stayed by the U.S.
Supreme Court and the EPA has proposed repealing.
The Company operates generating units in Connecticut, Delaware, Maryland, 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 re-evaluated the program and published a model rule 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.
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. The contribution of climate change to the frequency or intensity of weather-related events could affect NRG's
operations and planning process.
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 partially depends 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.
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 depend on 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.
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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.
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:
•
•
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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 Company's remaining 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. Currently, the Company has
recorded a valuation allowance of approximately $1.8 billion against NRG's net deferred tax assets that are not related to NRG
Yield, Inc. 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.
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
• NRG's ability to achieve its strategy of regularly returning capital to stockholders;
• NRG's ability to obtain and maintain retail market share;
• NRG's ability to successfully evaluate investments and achieve intended financial results in new business and growth
initiatives;
• NRG's ability to successfully integrate, realize cost savings and manage any acquired businesses; and
• NRG's ability to develop and maintain successful partnering relationships.
Forward-looking statements speak only as of the date they were made, and NRG Energy, Inc. undertakes no obligation to
publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The
foregoing review of factors that could cause NRG's actual results to differ materially from those contemplated in any forward-
looking statements included in this Annual Report on Form 10-K should not be construed as exhaustive.
Item 1B — Unresolved Staff Comments
None.
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:
• NRG's ability to achieve the expected benefits of its Transformation Plan;
• NRG's ability to engage in successful sales and divestitures as well as mergers and acquisitions activity;
• The potential adverse effects of the GenOn Entities' filings under Chapter 11 of the Bankruptcy Code and restructuring
transactions on NRG's operations, management and employees and the risks associated with operating NRG's business
during the restructuring process;
• Risks and uncertainties associated with the GenOn Entities' Chapter 11 Cases including the ability to achieve
anticipated benefits therefrom;
• General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel;
• Volatile power supply costs and demand for power;
• Changes in law, including judicial decisions;
• Hazards customary to the power production industry and power generation operations such as fuel and electricity price
volatility, unusual weather conditions (including wind and solar 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 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 changes in market rules, rates, tariffs and environmental laws;
•
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;
• Operating and financial restrictions placed on NRG and its subsidiaries that are contained in the indentures governing
NRG's outstanding notes, in NRG's Senior Credit Facility, and in debt and other agreements of certain of NRG subsidiaries
and project affiliates generally;
• 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;
• 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;
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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,
2017. 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, 2017. The following table
summarizes NRG's power production and cogeneration facilities by region:
Power Market
Plant Type
Primary Fuel
Location
Rated MW
Capacity
Net MW
Capacity(a)
%
Owned
Name of Facility
Gulf Coast
Bayou Cove(i)
Big Cajun I(i)
Big Cajun II(i)
Big Cajun II(i)
Big Cajun II(i)
Cedar Bayou
Cedar Bayou 4
Cottonwood(i)
Greens Bayou
Gregory
Limestone
Petra Nova Cogen
San Jacinto
South Texas Project(b)
Sterlington(i)
T.H. Wharton
W.A. Parish
W.A. Parish
East/West
Arthur Kill
Astoria Turbines
Conemaugh & Keystone
Conemaugh & Keystone
Connecticut Jet Power
Devon
Doga
Encina(f)
Fisk
Gladstone
Indian River
Indian River
Joliet(c)
Long Beach
Middletown
Midway-Sunset
Montville
Oswego
Powerton(c)
Saguaro
MISO
MISO
MISO
MISO
MISO
ERCOT
ERCOT
MISO
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
MISO
ERCOT
ERCOT
ERCOT
NYISO
NYISO
PJM
PJM
ISO-NE
ISO-NE
CAISO
PJM
PJM
PJM
PJM
CAISO
ISO-NE
CAISO
ISO-NE
NYISO
PJM
WECC
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Natural Gas
Natural Gas
Coal
Natural Gas
Coal
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Coal
Natural Gas
Natural Gas
Nuclear
Uranium
Natural Gas
Natural Gas
Coal
Natural Gas
LA
LA
LA
LA
LA
TX
TX
TX
TX
TX
TX
TX
TX
TX
LA
TX
TX
TX
225
430
580
540
588
1,495
498
1,263
344
388
1,689
44
162
2,582
176
1,025
2,504
1,145
225
430
580
540
341
1,495
249
1,263
344
388
1,689
22
162
1,136
176
1,025
2,504
1,145
Total Gulf Coast
15,678
13,714
NY
NY
PA
PA
CT
CT
Turkey
CA
IL
AUS
DE
DE
IL
CA
CT
CA
CT
NY
IL
NV
Natural Gas
Natural Gas
Coal
Oil
Oil
Oil
Natural Gas
Natural Gas
Oil
Coal
Coal
Oil
Natural Gas
Natural Gas
Oil
Natural Gas
Oil
Oil
Coal
Natural Gas
54
858
404
3,343
20
142
133
180
859
172
1,613
410
16
1,326
260
770
226
494
1,639
1,538
92
858
404
125
1
142
133
144
859
172
605
410
16
1,326
260
770
113
494
1,639
1,538
46
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
100.0
100.0
100.0
100.0
58.0
100.0
50.0
100.0
100.0
100.0
100.0
50.0
100.0
44.0
100.0
100.0
100.0
100.0
100.0
100.0
3.7
3.7
100.0
100.0
80.0
100.0
100.0
37.5
100.0
100.0
100.0
100.0
100.0
50.0
100.0
100.0
100.0
50.0
Name of Facility
Power Market
Plant Type
Primary Fuel
Location
Rated MW
Capacity
Net MW
Capacity(a)
%
Owned
East/West (continued)
San Diego Turbines(d)
SMECO
Sunrise
Vienna
Watson
Waukegan
Waukegan
Will County
CAISO
PJM
CAISO
PJM
CAISO
PJM
PJM
PJM
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Natural Gas
Natural Gas
Natural Gas
Oil
Natural Gas
Coal
Oil
Coal
CA
MD
CA
MD
CA
IL
IL
IL
61
78
586
167
416
682
108
510
61
78
586
167
204
682
108
510
Total East/West
17,103
12,451
Renewables
Agua Caliente(g)(j)
Blythe II
Broken Bow(g)
Cedro Hill(g)
Crofton Bluffs(g)
Distributed Solar
Eastridge(h)
Guam(j)
Ivanpah(g)(j)
Langford Wind Farm
Mountain Wind I(g)
Mountain Wind II(g)
Sherbino Wind Farm(j)
Spanish Town(j)
Stadiums(j)
NRG Yield
Agua Caliente(g)
Alpine
Alta Wind
Avenal
Avra Valley
Blythe
Borrego
Buffalo Bear
CAISO/WECC
Renewable
Solar
CAISO
MISO
ERCOT
MISO
Renewable
Solar
Renewable Wind
Renewable Wind
Renewable Wind
AZNMSNV/WECC Renewable
Solar
MISO
CAISO
ERCOT
WECC
WECC
ERCOT
Renewable Wind
Renewable
Solar
Renewable
Solar
Renewable Wind
Renewable Wind
Renewable Wind
Renewable Wind
Renewable
Solar
Renewable
Solar
CAISO/WECC
Renewable
Solar
CAISO
CAISO
CAISO
CAISO
CAISO
CAISO
SPP
Renewable
Solar
Renewable Wind
Renewable
Solar
Renewable
Solar
Renewable
Solar
Renewable
Solar
Renewable Wind
California Valley Solar Ranch CAISO/WECC
Renewable
Solar
Crosswinds
Desert Sunlight
Distributed Solar
Dover Cogeneration
El Segundo
Elbow Creek
Elkhorn Ridge
Forward
Four Brothers Solar
MISO
CAISO
Various
PJM
CAISO
ERCOT
MISO
PJM
WECC
Renewable Wind
Renewable
Solar
Renewable
Solar
Fossil
Fossil
Natural Gas
Natural Gas
Renewable Wind
Renewable Wind
Renewable Wind
Renewable
Solar
55
AZ
CA
NE
TX
NE
various
MN
Guam
CA
TX
WY
WY
TX
USVI
various
290
20
80
150
42
179
10
26
392
150
61
80
150
4
6
102
20
13
47
8
179
10
26
196
150
19
25
75
4
6
Total Renewables
1,640
880
AZ
CA
CA
CA
AZ
CA
CA
OK
OK
CA
IA
various
DE
CA
TX
NE
PA
UT
290
66
947
45
26
21
26
19
250
21
550
27
103
550
122
81
29
320
46
66
947
23
26
21
26
19
250
21
138
27
103
550
122
54
29
160
100.0
100.0
100.0
100.0
49.0
100.0
100.0
100.0
35.0
100.0
16.0
31.0
20.0
100.0
99.0
100.0
50.1
100.0
31.0
31.0
50.0
100.0
100.0
16.0
100.0
100.0
50.0
100.0
100.0
100.0
100.0
100.0
99.0
25.0
100.0
100.0
100.0
100.0
66.7
100.0
50.0
Name of Facility
Power Market
Plant Type
Primary Fuel
Location
Rated MW
Capacity
Net MW
Capacity(a)
%
Owned
Thermal Facilities
ISO-NE
ISO-NE
ERCOT
WECC
MISO
WECC
WECC
WECC
MISO
PJM
CAISO
MISO
PJM
PJM
PJM
WECC
MISO
SPP
Various
ERCOT
WECC
WECC
SPP
WECC
ISO-NE
ERCOT
CAISO
NRG Yield (continued)
GenConn Devon
GenConn Middletown
Goat Mountain Wind
Granite Mountain
Hardin
High Desert
Iron Springs
Kansas South
Laredo Ridge
Lookout
Marsh Landing
Odin
Paxton Creek Cogeneration
Pinnacle
Princeton Hospital(e)
Roadrunner
San Juan Mesa
Sleeping Bear
SPP projects
South Trent Wind Farm
Spanish Fork, UT
Spring Canyon II and III
Taloga
Tucson Convention Center
University of Bridgeport
Wildorado
Walnut Creek
Other
Residential solar
Fossil
Fossil
Dual-fuel
Dual-fuel
Renewable Wind
Renewable
Solar
Renewable Wind
Renewable
Solar
Renewable
Solar
Renewable
Solar
Renewable Wind
Renewable Wind
Fossil
Natural Gas
Renewable Wind
Fossil
Natural Gas
Renewable Wind
Fossil
Natural Gas
Renewable
Solar
Renewable Wind
Renewable Wind
Renewable
Solar
Renewable Wind
Renewable Wind
Renewable Wind
Renewable Wind
Fossil
Fossil
Natural Gas
Natural Gas
Renewable Wind
Fossil
Natural Gas
CT
CT
TX
UT
IA
CA
UT
CA
NE
PA
CA
MN
PA
WV
NJ
NM
NM
OK
various
TX
UT
CO
OK
AZ
CT
TX
CA
Total NRG Yield
NRG's Noncontrolling Interest
Net NRG Yield
50.0
50.0
100.0
50.0
99.0
100.0
50.0
100.0
100.0
100.0
100.0
99.9
100.0
100.0
100.0
100.0
75.0
100.0
100.0
100.0
100.0
90.1
100.0
100.0
100.0
100.0
100.0
190
190
150
130
15
20
80
20
80
38
95
95
150
65
15
20
40
20
80
38
720
720
20
12
55
5
20
120
95
25
101
19
60
130
2
1
161
485
6,437
20
12
55
5
20
90
95
25
101
19
54
130
2
1
161
485
5,241
(2,353)
2,888
Renewable
Solar
various
Total Other
114
114
114
114
100.0
Total
40,972
30,047
(a) Actual capacity can vary depending on factors including weather conditions, operational conditions, and other factors. Additionally, ERCOT requires periodic
demonstration of capability, and the capacity may vary individually and in the aggregate from time to time.
(b) Generation capacity figure consists of the Company's 44% interest in the two units at STP.
(c) NRG leases 100% interests in the Powerton facility and Units 7 and 8 of the Joliet facility through facility lease agreements expiring in 2034 and 2030,
respectively. NRG owns 100% interest in Joliet Unit 6. NRG operates the Powerton and Joliet facilities.
(d) These units are located on property owned by SDG&E under an annual license agreement. The Miramar and El Cajon sites (51 MW) retired on January, 1,
2017.
(e) The output of Princeton Hospital is primarily dedicated to serving the hospital. Excess power is sold to the local utility under its state-jurisdictional tariff.
(f) Encina Unit 1 was deactivated on March 31, 2017.
(g) Capacity attributable to noncontrolling interest for these Renewables facilities was 685 MWs as of December 31, 2017.
(h)
(i) Assets that are part of NRG's South Central business.
(j) Assets that are not included in the announced sale of NRG's ownership in NRG Yield, Inc. Agua Caliente remains as a ROFO asset under the ROFO
In January 2018, NRG sold the Eastridge assets to a third party.
Agreement between NRG and NRG Yield, Inc.
The Company's thermal businesses in Pittsburgh, Harrisburg and San Francisco are regulated by their respective state's Public
Utility Commission. The other thermal businesses are subject to contract terms with their customers. The Company's thermal
businesses are owned by NRG Yield LLC. The following table summarizes NRG's thermal steam and chilled water facilities as
of December 31, 2017:
Name and Location of
Facility
NRG Energy Center Minneapolis,
MN
NRG Energy Center San
Francisco, CA
NRG Energy Center Omaha, NE
NRG Energy Center Harrisburg,
PA
NRG Energy Center Phoenix, AZ
Thermal Energy
Purchaser
Approx 100 steam and
55 chilled water
customers
Approx 180 steam
customers
Approx 60 steam and
65 chilled water
customers
Approx 125 steam and
5 chilled water
customers
Approx 35 chilled
water customers
NRG Energy Center Pittsburgh, PA Approx 25 steam and
NRG Energy Center San Diego,
CA
NRG Energy Center Dover, DE
NRG Energy Center Princeton, NJ
25 chilled water
customers
Approx 20 chilled
water customers
Kraft Foods Inc. and
Procter & Gamble
Company
Princeton HealthCare
System
Total Generating
Capacity (MWt)
%
Owned
100
100
Rated Megawatt
Thermal
Equivalent
Capacity (MWt)
Net Megawatt
Thermal
Equivalent
Capacity (MWt)
Generating
Capacity
322
136
133
322
136
133
Steam: 1,100 MMBtu/hr.
Chilled water: 38,700 tons
Steam: 454 MMBtu/hr.
100
12(a)
100
0(a)
100
Steam: 485 MMBtu/hr
Steam: 250 MMBtu/hr
Chilled water: 22,000 tons
Chilled water: 7,250 tons
142
9
77
0
142
73
77
26
108
13
108
13
Steam: 370 MMBtu/hr.
Chilled water: 3,600 tons
24(a)
100
12(a)
0(a)
100
100
100
100
5
104
14
28
88
49
31
66
21
17
1
104
2
0
88
49
Steam: 17 MMBtu/hr
Chilled water: 29,600 tons
Chilled water: 3,920 tons
Chilled water: 8,000 tons
Steam: 302 MMBtu/hr.
Chilled water: 13,874 tons
31 Chilled water: 8,825 tons
66
Steam: 225 MMBtu/hr.
21
17
Steam: 72 MMBtu/hr.
Chilled water: 4,700 tons
1,453
1,319
(a) Net MWt capacity excludes 134 MWt available under the right-to-use provisions contained in agreements between two of NRG Yield Inc.'s thermal facilities
and certain of its customers.
Other Properties
NRG owns several real properties and facilities related to its generation assets, other vacant real property unrelated to the
Company's generation assets, interests in construction projects, and properties not used for operational purposes. NRG believes
it has satisfactory title to its plants and facilities in accordance with standards generally accepted in the electric power industry,
subject to exceptions that, in the Company's opinion, would not have a material adverse effect on the use or value of its portfolio.
NRG leases its financial and commercial corporate headquarters at 804 Carnegie Center, Princeton, New Jersey, its operational
headquarters in Houston, Texas, its retail business offices and call centers, and various other office space.
56
57
Item 3 — Legal Proceedings
PART II
See Item 15 — Note 22, Commitments and Contingencies, to the Consolidated Financial Statements for discussion of the
Item 5 — Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
material legal proceedings to which NRG is a party.
Item 4 — Mine Safety Disclosures
Not applicable.
Market Information and Holders and Dividends
NRG's authorized capital stock consists of 500,000,000 shares of NRG common stock and 10,000,000 shares of preferred
stock. A total of 25,000,000 shares of the Company's common stock are authorized for issuance under the NRG LTIP. No shares
of NRG common stock were available for future issuance under the NRG GenOn LTIP. For more information about the NRG
LTIP and the NRG GenOn LTIP, refer to Item 12 — Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters and Item 15 — Note 20, Stock-Based Compensation, to the Consolidated Financial Statements.
NRG's common stock is listed on the New York Stock Exchange and has been assigned the symbol: NRG. The high and
low sales prices, as well as the closing price for the Company's common stock on a per share basis for 2017 and 2016 are set forth
below:
Common Stock Price
High
Low
Closing
Dividends Per
Common Share
Fourth
Quarter
2017
Third
Quarter
2017
Second
Quarter
2017
First
Quarter
2017
Fourth
Quarter
2016
Third
Quarter
2016
Second
Quarter
2016
First
Quarter
2016
$
$
29.78
24.55
28.48
$
26.25
15.95
25.59
$
19.07
14.52
17.22
$
18.95
12.19
18.70
$
13.06
9.84
12.26
$
16.02
10.70
11.21
$
18.32
11.69
14.99
14.47
8.92
13.01
$
0.030
$
0.030
$
0.030
$
0.030
$
0.030
$
0.030
$
0.030
$
0.145
NRG had 316,743,089 shares outstanding as of December 31, 2017. As of January 31, 2018, there were 317,637,917 shares
outstanding, and there were 21,150 common stockholders of record.
On January 19, 2018, NRG declared a quarterly dividend on the Company's common stock of $0.030 per share, or $0.12
per share on an annualized basis, payable on February 15, 2018, to stockholders of record as of February 1, 2018.
The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated
laws and regulations.
58
59
Stock Performance Graph
The performance graph below compares NRG's cumulative total stockholder return on the Company's common stock for
the period December 31, 2012 through December 31, 2017 with the cumulative total return of the Standard & Poor's 500 Composite
Stock Price Index, or S&P 500, and the Philadelphia Utility Sector Index, or UTY. NRG's common stock trades on the New York
Stock Exchange under the symbol "NRG."
The performance graph shown below is being furnished and compares each period assuming that $100 was invested on
December 31, 2012, in each of the common stock of NRG, the stocks included in the S&P 500 and the stocks included in the UTY,
and that all dividends were reinvested.
Comparison of Cumulative Total Return
NRG Energy, Inc.
S&P 500
UTY
Dec-2012
Dec-2013
Dec-2014
Dec-2015
Dec-2016
Dec-2017
$
$
100.00
100.00
100.00
$
127.02
132.39
110.98
$
121.33
150.51
143.09
54.56
152.59
134.14
$
58.06
170.84
157.47
$
135.68
208.14
177.66
Item 6 — Selected Financial Data
The following table presents NRG's historical selected financial data. This historical data should be read in conjunction with
the Consolidated Financial Statements and the related notes thereto in Item 15 and Item 7, Management's Discussion and Analysis
of Financial Condition and Results of Operations. The Company has completed several acquisitions and dispositions, as described
in Item 15 — Note 3, Discontinued Operations, Acquisitions and Dispositions.
Year Ended December 31,
2017
2016
2015
2014
2013
(In millions except ratios and per share data)
$ 8,820
(8,944)
$ 12,810
(13,033)
(15)
895
(459)
198
(99)
(308)
(43)
(386)
323
323
324
$
—
(72)
204
134
334
339
337
0.23
0.54
$ (1.22)
0.45
34.68
$ 32.33
1,559
2,757
0.98
0.89
$ 1,149
2,767
0.36
0.36
$
$
$
$
Statement of income data:
Total operating revenues
Total operating costs and other expenses (a)
Impairment losses (b)
Operating (loss)/income
Impairment losses on investments
Loss from continuing operations, net
(Loss)/income from discontinued operations, net
Net (loss)/income attributable to NRG Energy, Inc.
Common share data:
Basic shares outstanding — average
Diluted shares outstanding — average
Shares outstanding — end of year
Per share data:
$ 10,629
$ 10,512
$ 12,328
(10,484)
(10,633)
(12,612)
(1,709)
(587)
(79)
(1,548)
(789)
$ (2,153)
317
317
317
(702)
266
(268)
(983)
92
(774)
316
316
315
(4,860)
(4,051)
(56)
(6,331)
(105)
$ (6,382)
329
329
314
$
Net (loss)/income attributable to NRG — basic and diluted
$ (6.79)
$ (2.22)
$ (19.46)
Dividends declared per common share
Book value
Business metrics:
Cash flow from operations
Liquidity position (c)
Ratio of earnings to fixed charges
Ratio of earnings to fixed charges and preferred dividends
Return on equity
Ratio of debt to total capitalization
Balance sheet data:
Current assets
Current liabilities
Property, plant and equipment, net
Total assets
Long-term debt, including current maturities, and capital
leases
Total stockholders' equity
(a) Excludes impairment losses and impairment losses on investments.
0.12
6.20
$
0.24
0.58
$ 14.09
$ 17.29
$ 1,387
$ 2,088
$ 1,349
3,210
(0.52)
(0.52)
2,373
0.29
0.29
2,418
(4.01)
(3.88)
(109.40)% (17.41)% (117.45)%
1.15%
(3.69)%
88.70 %
77.75 %
72.58 %
56.98%
52.81 %
$ 4,415
$ 6,714
$ 7,619
$
8,784
$ 7,776
3,317
13,908
23,318
4,702
15,369
30,682
4,602
15,901
33,125
5,236
19,321
40,856
4,381
16,676
34,081
16,404
16,473
16,698
17,047
13,485
$ 1,968
$ 4,446
$ 5,434
$ 11,676
$ 10,467
(b)
Includes goodwill impairment as described in Item 15 - Note 11, Goodwill and Other Intangibles, to the Consolidated Financial Statements.
(c) Liquidity position is determined as disclosed in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, Liquidity
and Capital Resources, Liquidity Position. It excludes collateral funds deposited by counterparties of $37 million, $2 million, and $91 million as of
December 31, 2017, 2016 and 2015, respectively, which represents cash held as collateral from hedge counterparties in support of energy risk management
activities. It is the Company's intention to limit the use of these funds for repayment of the related current liability for collateral received in support of energy
risk management activities.
60
61
The following table provides the details of NRG's operating revenues:
Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations
Energy revenue
Capacity revenue
Retail revenue
Mark-to-market for economic hedging activities
Contract amortization
Other revenues
Corporate/Eliminations
Total operating revenues(a)
2017
3,549
1,197
6,385
21
(56)
490
(957)
10,629
$
$
$
$
(a) Inter-segment sales and net derivative gains and losses included in operating revenues.
2014
2016
$
Year Ended December 31,
2015
(In millions)
4,923
$
1,368
6,910
(143)
(40)
425
(1,115)
12,328
4,122
1,236
6,336
(572)
(56)
543
(1,097)
10,512
$
$
4,960
1,201
7,372
690
(12)
536
(1,937)
12,810
$
$
2013
3,638
936
6,315
(185)
(32)
287
(2,139)
8,820
Energy revenue consists of revenues received from third parties as well as from the Company's retail businesses, for sales
of electricity in the day-ahead and real-time markets, as well as bilateral sales. It also includes energy sold through long-term
PPAs for renewable facilities. In addition, energy revenue includes revenues from the settlement of financial instruments and net
realized trading revenues.
Capacity revenue consists of revenues received from a third party at either the market or negotiated contract rates for making
installed generation capacity available in order to satisfy system integrity and reliability requirements. Capacity revenue also
includes revenues from the settlement of financial instruments. In addition, capacity revenue includes revenues received under
tolling arrangements, which entitle third parties to dispatch NRG's facilities and assume title to the electrical generation produced
from that facility.
Retail revenue, representing operating revenues of NRG's retail businesses, consists of revenues from retail sales to
residential, small business, commercial, industrial and governmental/institutional customers, revenues from the sale of excess
supply into various markets, primarily in Texas, as well as product sales.
Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow
hedges and ineffectiveness on cash flow hedges.
Contract amortization revenue consists of the amortization of the intangible assets for net in-market C&I contracts established
in connection with the acquisitions of Reliant Energy and Green Mountain Energy, as well as acquired power contracts, gas
derivative instruments, and certain power sales agreements assumed at Fresh Start and Texas Genco purchase accounting dates
related to the sale of electric capacity and energy in future periods. These amounts are amortized into revenue over the term of
the underlying contracts based on actual generation or contracted volumes.
Other revenues include revenues generated by the Thermal Business consisting of revenues received from the sale of steam,
hot and chilled water generally produced at a central district energy plant and sold to commercial, governmental and residential
buildings for space heating, domestic hot water heating and air conditioning. It also includes the sale of high-pressure steam
produced and delivered to industrial customers that is used as part of an industrial process. Other revenues also consists of
operations and maintenance fees, or O&M fees, construction management services, or CMA fees, sale of natural gas and emission
allowances, and revenues from ancillary services. O&M fees consist of revenues received from providing certain unconsolidated
affiliates with services under long-term operating agreements. CMA fees are earned where NRG provides certain management
and oversight of construction projects pursuant to negotiated agreements such as for the GenConn, Cedar Bayou 4 and certain
solar construction projects. Ancillary services are comprised of the sale of energy-related products associated with the generation
of electrical energy such as spinning reserves, reactive power and other similar products. Other revenues also include unrealized
trading activities.
The discussion and analysis below has been organized as follows:
• Executive Summary, including the business environment in which NRG operates, a discussion of regulation, weather,
competition and other factors that affect the business, and significant events that are important to understanding the results
of operations and financial condition;
• Results of operations, including an explanation of significant differences between the periods in the specific line items
of NRG's Consolidated Statements of Operations;
•
Financial condition addressing credit ratings, liquidity position, sources and uses of cash, capital resources and
requirements, commitments, and off-balance sheet arrangements; and
• Critical accounting policies which are most important to both the portrayal of the Company's financial condition and
results of operations, and which require management's most difficult, subjective or complex judgment.
As you read this discussion and analysis, refer to NRG's Consolidated Statements of Operations to this Form 10-K, which
presents the results of the Company's operations for the years ended December 31, 2017, 2016, and 2015, and also refer to Item 1
to this Form 10-K for more detailed discussion about the Company's business.
Executive Summary
NRG Energy, Inc., or NRG or the Company, is a leading integrated power company built on the strength of a 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 30,000 MW of
generation; trades 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.
Business Environment
The industry dynamics and external influences affecting the Company and its businesses, and the power generation and
retail energy industry in general in 2017 and for the future medium term include:
Capacity Markets — Capacity markets are a major source of revenue for the Company. Centralized capacity markets exist
in ISO-NE, MISO, NYISO and PJM. Bilateral markets exist in CAISO and MISO. These auctions are either an annual market
held three years ahead of the delivery period as in the case of PJM and ISO-NE, or six months to one month ahead as in the case
of NYISO. Many variables affect the prices derived in these auctions. These variables include the load forecast, the target reserve
margin, rules surrounding demand response, capacity performance penalties, capacity imports and exports from the region, new
generation entrants, slope of the demand curve, generation retirements, the cost of retrofitting old generation to meet new
environmental rules, expected profitability of the units themselves in the energy market and various other auction rules. In theory,
a high capacity price indicates that the ISO doesn't have sufficient generation capacity against its needed reserve margin and new
construction should enter the market. Similarly, a low capacity price suggests the market is over-built and units should retire. The
Company has seen many swings in the pricing for capacity markets and the rules in many of the markets are undergoing significant
changes, as discussed in this Management's Discussion and Analysis of Financial Condition and Results of Operations.
Commodities Markets — The price of natural gas plays an important role in setting the price of electricity in many of the
regions where NRG operates power plants. Natural gas prices are driven by variables including demand from the industrial,
residential, and electric sectors, productivity across natural gas supply basins, costs of natural gas production, changes in pipeline
infrastructure, and the financial and hedging profile of natural gas consumers and producers. In 2017, average natural gas prices
at Henry Hub were 26.3% higher than in 2016.
If long-term gas prices decrease, the Company is likely to encounter lower realized energy prices, leading to lower energy
revenues as higher priced hedge contracts mature and are replaced by contracts with lower gas and power prices. NRG's retail
gross margins have historically improved as natural gas prices decline and are likely to partially offset the impact of declining gas
prices on conventional wholesale power generation. To further mitigate this impact, NRG may increase its percentage of coal and
nuclear capacity sold forward using a variety of hedging instruments, as described under the heading "Energy-Related
Commodities" in Item 15 — Note 5, Accounting for Derivative Instruments and Hedging Activities, to the Consolidated Financial
Statements.
62
63
Natural gas prices are a primary driver of coal demand. The low priced commodity environment has stressed coal equities,
leading coal suppliers to file for bankruptcy protection, launch debt exchanges, rationalize assets, and cut production. If multiple
parties withdraw from the market, liquidity could be challenged in the short term. Inventory overhang will be utilized to offset
production losses. Coal prices are typically affected by the price of natural gas.
Electricity Prices — The price of electricity is a key determinant of the profitability of the Company. Many variables such
as the price of different fuels, weather, load growth and unit availability all coalesce to impact the final price for electricity and
the Company's profitability. The following table summarizes average on-peak power prices for each of the major markets in which
NRG operates for the years ended December 31, 2017, 2016, and 2015. For the year ended December 31, 2017 as compared to
the same period in 2016, the average on-peak power prices increased primarily due to the increase in natural gas prices. For the
year ended December 31, 2016 as compared to the same period in 2015 the average on-peak power prices decreased primarily
due to the decrease in natural gas prices.
Region
Gulf Coast (a)
ERCOT - Houston(b)
ERCOT - North(b)
MISO - Louisiana Hub(c)
East/West
NY J/NYC(c)
NEPOOL(c)
COMED (PJM)(c)
PJM West Hub(c)
CAISO - NP15(c)
CAISO - SP15(c)
Average on Peak Power Price ($/MWh)
Year Ended December 31
2016
2015
2017
2017 vs 2016
Change %
2016 vs 2015
Change %
$
33.95
$
26.91
$
25.86
40.02
38.34
37.18
32.46
34.14
35.68
36.48
24.53
34.30
35.29
35.05
32.11
33.79
31.73
31.17
28.15
27.61
34.55
46.42
48.25
34.13
41.97
35.50
32.45
26%
5%
17%
9%
6%
1%
1%
12%
17%
(4)%
(11)%
(1)%
(24)%
(27)%
(6)%
(19)%
(11)%
(4)%
(a) Gulf Coast region also transacts in PJM - West Hub.
(b) Average on-peak power prices based on real time settlement prices as published by the respective ISOs.
(c) Average on-peak power prices based on day ahead settlement prices as published by the respective ISOs.
The following table summarizes average realized power prices for each region in which NRG operates for the years ended
December 31, 2017, 2016, and 2015, which reflects the impact of settled hedges.
Region
Gulf Coast
East/West
Average Realized Power Price ($/MWh)
Year Ended December 31
2016
2015
2017
2017 vs 2016
Change %
2016 vs 2015
Change %
$
$
36.43
62.07
$
43.34
64.16
42.89
68.79
(16)%
(3)%
1 %
(7)%
Though the average on peak power prices have increased on average by 9% for the year ended December 31, 2017 as
compared to the same period in 2016, and decreased on average by 15% for the year ended December 31, 2016 as compared to
the same period in 2015, average realized prices by region for the Company were driven by the Company's multi-year hedging
program and the success of the Company's commercial operations team in optimizing the value of the Company's assets on a
daily basis.
Environmental Regulatory Landscape — The MATS rule, finalized in 2012, had been the primary regulatory force behind
the decision to retrofit, repower or retire uncontrolled coal fired power plants. In June 2015, the U.S. Supreme Court held that the
EPA unreasonably refused to consider costs when it determined 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. On April 18, 2017, the EPA asked the D.C. Circuit
to postpone oral argument that had been scheduled for May 18, 2017 because the EPA is closely reviewing the supplemental
finding to determine whether it should reconsider all or part of the rule. On April 27, 2017, the D.C. Circuit granted the EPA's
request to postpone the oral argument and hold the case in abeyance. A number of regulations on GHGs, ambient air quality, coal
combustion byproducts and water use with the potential for increased capital costs or operational impacts have been finalized and
are under review by the courts and being re-evaluated by the current Administration. The design, timing and stringency of these
regulations and the legal outcomes will affect the decision to retrofit or retire existing fossil plants. See Item 1— Business,
Environmental Matters, for further discussion.
Public Policy Support and Government Financial Incentives for Clean Infrastructure Development — Policy mechanisms
including production and investment tax credits, cash grants, loan guarantees, accelerated depreciation tax benefits, RPS, and
carbon trading plans 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 of the Company's development program. In December 2015, the U.S.
Congress enacted an extension of the 30% solar ITC so that projects that 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 that began construction in years
2016 through 2019. Wind projects that begin construction in the years 2017, 2018 and 2019 are eligible for PTC at 80%, 60%
and 40% of the statutory rate per kilowatt hour respectively.
Weather — Weather conditions in the regions of the U.S. in which NRG does business influence the Company's financial
results. Weather conditions can affect the supply and demand for electricity and fuels. Weather may also impact the availability
of the Company's generating assets. Changes in energy supply and demand may impact the price of these energy commodities in
both the spot and forward markets, which may affect the Company's results in any given period. Typically, demand for and the
price of electricity is higher in the summer and the winter seasons, when temperatures are more extreme. The demand for and
price of natural gas is also generally higher in the winter. However, all regions of the U.S. typically do not experience extreme
weather conditions at the same time, thus NRG is typically not exposed to the effects of extreme weather in all parts of its business
at once.
Wind and Solar Resource Availability — The availability of the wind and solar resources affects the financial performance
of the wind and solar facilities, which may impact the Company’s overall financial performance. Due to the variable nature of the
wind and solar resources, the Company cannot predict the availability of the wind and solar resources and the potential variances
from expected performance levels from quarter to quarter. To the extent the wind and solar resources are not available at expected
levels, it could have a negative impact on the Company’s financial performance for such periods.
ERCOT Retirements — A number of announced retirement notices of coal generating facilities owned by others in Texas
could lower reserve margins in ERCOT. This trend of retirement notices could have an effect on the Company’s results of operations
and future business performance, particularly in the ERCOT market.
Net Impact of Tax Reform — The Tax Cuts and Jobs Act of 2017, or the Tax Act, which was signed into law on December
22, 2017, makes significant changes to the taxation of U.S. businesses. These changes include a permanent reduction to the federal
corporate income tax rate, changes in the deductibility of interest on certain debt obligations and limiting the amount of NOL
available to offset taxable income, among other things. The Tax Act requires the Company to revalue its deferred tax assets, which
reduced the Company’s deferred tax assets by $733 million offset by valuation allowance of $660 million. In addition, the Company
established a non-current receivable for its refundable AMT credits of $64 million, net of sequestration. The net impact of the
Tax Act on net income is a decrease of $9 million due to the expense of $73 million resulting from the Company's revaluation of
its net deferred tax asset, partially offset by a $64 million benefit from establishing the AMT credit receivable.
64
65
Other Factors — A number of other factors significantly influence the level and volatility of prices for energy commodities
Significant Events
and related derivative products for NRG's business. These factors include:
NRG Transformation Plan
•
•
•
•
•
•
•
seasonal, daily and hourly changes in demand;
extreme peak demands;
available supply resources;
transportation and transmission availability and reliability within and between regions;
location of NRG's generating facilities relative to the location of its load-serving opportunities;
procedures used to maintain the integrity of the physical electricity system during extreme conditions; and
changes in the nature and extent of federal and state regulations.
• NRG is in process of executing its Transformation Plan. The three-part, three-year plan is comprised of targets in the
areas of operational and cost excellence, portfolio optimization, and capital structure and allocation enhancement. For
further discussion, refer to Item 1 - Business.
• During 2017, NRG received cash proceeds from asset sales in the amount of $150 million, which includes the sales to
NRG Yield, Inc. (also included below in Transfers of Assets Under Common Control) and sale of Minnesota wind projects
to third parties.
• On February 6, 2018, NRG entered into a purchase and sale agreement with GIP to sell NRG's ownership in NRG Yield,
These factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects
Inc. and NRG's renewables platform for a total purchase price of $1.375 billion, subject to certain conditions.
may vary throughout the country as a result of regional differences in:
• weather conditions;
• market liquidity;
•
•
•
capability and reliability of the physical electricity and gas systems;
local transportation systems; and
the nature and extent of electricity deregulation.
Environmental Matters, Regulatory Matters and Legal Proceedings — Details of environmental matters are presented in
Item 15 — Note 24, Environmental Matters, to the Consolidated Financial Statements and Item 1— Business, Environmental
Matters, section. Details of regulatory matters are presented in Item 15 — Note 23, Regulatory Matters, to the Consolidated
Financial Statements and Item 1— Business, Regulatory Matters, section. Details of legal proceedings are presented in
Item 15 — Note 22, Commitments and Contingencies, to the Consolidated Financial Statements. Some of this information relates
to costs that may be material to the Company's financial results.
• On February 6, 2018, NRG entered into a purchase and sale agreement with Cleco to sell NRG's South Central business
for a total purchase price of $1.0 billion, subject to certain adjustments.
• On January 24, 2018, the Company entered into an agreement with NRG Yield, Inc. to sell 100% of its ownership interest
in Buckthorn Solar for cash consideration of $42 million, subject to other adjustments.
• On February 6, 2018, the Company entered into an agreement with NRG Yield, Inc. to sell 100% of the membership
interests in Carlsbad Energy Holdings LLC, which owns the Carlsbad project, a 527 MW natural gas fired project in
Carlsbad, CA, pursuant to the ROFO Agreement. The purchase price for the transaction is $365 million in cash
consideration, subject to customary working capital and other adjustments.
• On February 23, 2018, the Company entered into an agreement to sell BETM to a third party for $70 million. The
transaction is expected to close in the second half of 2018 and is subject to various customary closing conditions, approvals
and consents.
GenOn Chapter 11 Bankruptcy Filing
• On June 14, 2017, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the
Bankruptcy Court. On December 12, 2017, the Bankruptcy Court entered an order confirming the plan of reorganization.
For further discussion, refer to Item 15 — Note 1, Nature of Business, Note 3, Discontinued Operations, Acquisitions
and Dispositions, and Note 21, Related Party Transactions, to the Consolidated Financial Statements.
Tax Act
• As of December 31, 2017, as a result of the Tax Act, the Company reduced its deferred tax assets by $733 million offset
by valuation allowance of $660 million. In addition, the Company established a non-current receivable for its refundable
AMT credits of $64 million, net of sequestration. The net impact of the Tax Act on net income is a decrease of $9 million
primarily due to the expense of $73 million resulting from the Company's revaluation of its net deferred tax asset, partially
offset by a $64 million benefit from establishing the AMT credit receivable.
Transfers of Assets Under Common Control
• During 2017, the Company completed the sale of several projects totaling 555 MW to NRG Yield, Inc. for aggregate
cash consideration of approximately $245 million, as discussed in more detail in Item 15 — Note 3, Discontinued
Operations, Acquisitions and Dispositions, to the Consolidated Financial Statements.
Financing Activities
• Debt Issuances — During 2017, the Company issued approximately $0.9 billion in recourse debt, approximately $0.8
billion in non-recourse debt and repriced the 2023 Term Loan Facility as discussed in more detail in Item 15 - Note 12,
Debt and Capital Leases, to the Consolidated Financial Statements.
• Debt Repurchases — During 2017, the Company repurchased $1.5 billion in aggregate principal of outstanding Senior
Notes for approximately $1.5 billion, including accrued interest, as discussed in more detail in Item 15 - Note 12, Debt
and Capital Leases, to the Consolidated Financial Statements.
66
67
Extreme Weather Events
•
•
In late August 2017, Hurricane Harvey made landfall on the Texas coast. During the third quarter of 2017, the Company’s
Retail business was impacted by Hurricane Harvey by approximately $20 million.
In addition, during August 2017, NRG's Cottonwood generating station was damaged when the Sabine River Authority
opened the floodgates of the Toledo Bend reservoir, which resulted in downstream flooding of the Sabine River. The
generating station was returned to service during the fourth quarter of 2017. The Company estimates the impact of the
Cottonwood damage and Hurricane Harvey on Gulf Coast Generation to be approximately $20 million.
Impairments
•
•
Impairment losses — During 2017, the Company recorded impairment losses of $1.7 billion as discussed in more detail
in Item 15 — Note 10, Asset Impairments and Note 11, Goodwill and Other Intangibles, to the Consolidated Financial
Statements.
Impairment losses on Investments — During 2017, the Company recorded impairment losses of $79 million related
primarily to Petra Nova, as discussed in more detail in Item 15 — Note 10, Asset Impairments, to the Consolidated
Financial Statements.
Operational Matters
Bacliff Project
On June 16, 2017, the Company provided notice to BTEC New Albany, LLC that NRG Texas Power LLC was exercising
its right to terminate the Amended and Restated Membership Interest Purchase Agreement, or MIPA, due to the Bacliff Project,
a new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial completion by the
contractual expiration date of May 31, 2017. On July 14, 2017, the Company gave notice to BTEC New Albany, LLC that it owes
NRG Texas Power LLC approximately $48 million under the terminated MIPA, consisting of $38 million in purchaser incurred
costs and $10 million in liquidated damages. On July 18, 2017, BTEC filed a lawsuit alleging that NRG Texas Power LLC breached
the MIPA by improperly terminating it, and seeks a declaratory judgment as to the rights and obligations of the parties. On August
14, 2017, NRG filed its answer. On September 7, 2017, NRG filed a counterclaim for breach of contract seeking damages in
excess of $48 million.
Consolidated Results of Operations for the years ended 2017 and 2016
The following table provides selected financial information for the Company:
(in millions except otherwise noted)
Operating Revenues
Energy revenue (a)
Capacity revenue (a)
Retail revenue
Mark-to-market for economic hedging activities
Contract amortization
Other revenues (b)
Total operating revenues
Operating Costs and Expenses
Cost of sales (b)
Mark-to-market for economic hedging activities
Contract and emissions credit amortization (c)
Operations and maintenance
Other cost of operations
Total cost of operations
Depreciation and amortization
Impairment losses
Selling, general and administrative
Reorganization costs
Development costs
Total operating costs and expenses
Other income - affiliate
Gain/(loss) on sale of assets
Operating (Loss)/ Income
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates
Impairment losses on investments
Other income, net
Net loss on debt extinguishment
Interest expense
Total other (expense)/income
Loss from Continuing Operations Before Income Taxes
Income tax expense
Loss from Continuing Operations
(Loss)/income from discontinued operations, net of income tax
Net Loss
Less: Net loss attributable to noncontrolling interests and redeemable
noncontrolling interests
Net Loss Attributable to NRG Energy, Inc.
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)
Includes realized gains and losses from financially settled transactions.
Includes unrealized trading gains and losses.
(a)
(b)
(c) Includes amortization of SO2 and NOx credits and excludes amortization of RGGI credits.
Year Ended December 31,
2017
2016
Change
$
2,461
1,186
6,388
239
(56)
411
10,629
5,698
46
34
1,393
365
7,536
1,056
1,709
907
44
67
11,319
87
16
(587)
31
(79)
38
(53)
(890)
(953)
(1,540)
8
(1,548)
(789)
(2,337)
$
3,131
1,225
6,357
(642)
(56)
497
10,512
5,827
(508)
43
1,599
340
7,301
1,172
702
1,095
—
89
10,359
193
(80)
266
27
(268)
34
(142)
(895)
(1,244)
(978)
5
(983)
92
(891)
(670)
(39)
31
881
—
(86)
117
129
(554)
9
206
(25)
(235)
116
(1,007)
188
(44)
22
(960)
(106)
96
(853)
4
189
4
89
5
291
(562)
3
(565)
(881)
(1,446)
(184)
(2,153) $
(117)
(774) $
(67)
(1,379)
3.11
$
2.46
26%
$
$
$
68
69
Gross Margin
The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of sales,
which includes cost of fuel, other costs of sales, contract and emission credit amortization and mark-to-market for economic
hedging activities.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin,
which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the
GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a
substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic
gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors
as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined
as the sum of energy revenue, capacity revenue and other revenue, less cost of fuels and other cost of sales.
Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract
amortization, emission credit amortization, or other operating costs.
The tables below present the composition and reconciliation of gross margin and economic gross margin which reflects the
Company's current view of reporting segments for the years ended December 31, 2017 and 2016:
Year Ended December 31, 2017
(In millions except otherwise noted)
Energy revenue
Capacity revenue
Retail revenue
Mark-to-market for economic hedging activities
Contract amortization
Other revenue(b)
Operating revenue
Cost of fuel
Other costs of sales(c)
Mark-to-market for economic hedging
activities
Contract and emission credit amortization
Generation
Gulf
Coast
East/
West(a)
$ 1,806
$
266
—
72
14
186
2,344
(994)
(344)
(20)
(30)
830
585
—
(35)
—
49
1,429
(401)
(238)
11
(4)
Subtotal
Retail
Renewables
$ 2,636
$
— $
359
$
851
—
37
14
235
3,773
(1,395)
—
6,385
(4)
(1)
—
6,380
(12)
(582)
(4,756)
(9)
(34)
181
—
—
—
(12)
—
77
424
(4)
(11)
—
—
NRG
Yield
Corporate/
Eliminations
Total
554
346
—
—
(69)
178
1,009
(35)
(28)
—
—
$
(1,088) $
(11)
3
218
—
(79)
(957)
45
1,080
(218)
—
2,461
1,186
6,388
239
(56)
411
10,629
(1,401)
(4,297)
(46)
(34)
Gross margin
$
956
$
797
$ 1,753
$ 1,793
$
409
$
946
$
(50) $
4,851
Less: Mark-to-market for economic hedging
activities, net
Less: Contract and emission credit amortization,
net
52
(16)
(24)
28
177
(4)
(20)
(1)
(12)
—
—
(69)
—
—
193
(90)
Economic gross margin
$
920
$
825
$ 1,745
$ 1,617
$
421
$ 1,015
$
(50) $
4,748
Business Metrics
MWh sold (thousands)(d)(e)
MWh generated (thousands)(f)
53,802
49,574
19,954
13,373
3,836
3,836
6,880
8,761
(a) Includes International, BETM and Generation eliminations.
(b) Renewables Other revenue includes $29 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits.
(d) MWh sold excludes generation at facilities in the West and NRG Yield that generate revenue under tolling agreements.
(e) Does not include MWh of 35 thousand or MWt of 1,926 thousand for thermal sold by NRG Yield.
(f) Does not include MWh of 108 thousand or MWt of 1,926 thousand for thermal generated by NRG Yield.
Year Ended December 31, 2016
Generation
Gulf
Coast
East/
West(a)
Subtotal
Retail
Renewables
NRG
Yield
Corporate/
Eliminations
Total
$ 2,073
$ 1,098
$ 3,171
$
— $
369
$
Mark-to-market for economic hedging activities
(518)
(In millions except otherwise noted)
Energy revenue
Capacity revenue
Retail revenue
Contract amortization
Other revenue (b)
Operating revenue
Cost of fuel
Other costs of sales(c)
Mark-to-market for economic hedging
activities
Contract and emission credit amortization
293
—
15
237
598
—
(48)
—
85
2,100
1,733
(938)
(387)
71
(29)
(469)
(299)
2
(5)
891
—
(566)
15
322
—
6,336
—
(1)
—
3,833
(1,407)
6,335
(8)
(686)
(4,679)
73
(34)
365
(6)
—
—
(6)
(1)
44
406
(3)
(11)
—
—
Gross margin
$
817
$
962
$ 1,779
$ 2,007
$
392
$
968
$
Less: Mark-to-market for economic hedging
activities, net
Less: Contract and emission credit amortization,
net
(447)
(46)
(493)
365
(14)
(5)
(19)
(7)
(6)
(1)
—
(75)
Economic gross margin
$ 1,278
$ 1,013
$ 2,291
$ 1,649
$
399
$ 1,043
$
Business Metrics
MWh sold (thousands)(d)(e)
MWh generated (thousands)(f)
52,929
47,828
25,995
17,114
3,827
3,827
7,363
9,264
(a) Includes International, BETM and Generation eliminations.
(b) Renewables Other revenue includes $19 million of intercompany revenue to NRG Yield.
(c) Includes purchased energy, capacity and emissions credits.
(d) MWh sold excludes generation at facilities in the West and NRG Yield that generate revenue under tolling agreements.
(e) Does not include MWh of 71 thousand or MWt of 1,966 thousand for thermal sold by NRG Yield.
(f) Does not include MWh of 275 thousand or MWt of 1,966 thousand for thermal generated by NRG Yield.
The table below represents the weather metrics for 2017 and 2016:
582
345
—
—
(69)
177
$
(991) $
(11)
21
(70)
—
(46)
1,035
(1,097)
(33)
(28)
—
(6)
3,131
1,225
6,357
(642)
(56)
497
10,512
(1,321)
(4,506)
508
(43)
$
5,150
(134)
(99)
$
5,383
130
898
70
3
4
—
3
1
Years ended
December 31,
Quarters ended
December 31,
Quarters ended
September 30,
Quarters ended
June 30,
Quarters ended
March 31,
Weather Metrics
Gulf
Coast(b)
East/West
Gulf
Coast(b)
East/West
Gulf
Coast(b)
East/West
Gulf
Coast(b)
East/West
Gulf
Coast(b)
East/West
2017
CDDs(a)
HDDs(a)
2016
CDDs
HDDs
10 year average
CDDs
HDDs
2,949
1,383
2,966
1,529
2,904
1,903
1,155
3,199
1,169
3,191
1,043
3,504
296
710
362
545
249
736
84
1,157
71
1,145
67
1,227
1,528
1
1,655
—
1,617
6
770
34
806
23
705
40
921
41
873
53
957
75
281
380
273
410
254
438
204
631
76
931
81
1,086
20
1,628
19
1,613
17
1,799
(a) National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a
particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is
below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period.
(b) CDDs/HDDs for the Gulf Coast region represent an average of cumulative population-weighted CDDs/HDDs for Texas and the West South-Central Climate region.
70
71
Generation gross margin and economic gross margin
Generation gross margin decreased $26 million and economic gross margin decreased $546 million, both of which
include intercompany sales, during the year ended December 31, 2017 compared to the same period in 2016.
The tables below describe the changes in Generation gross margin and in economic gross margin:
Gulf Coast Region
Lower gross margin due to a 14% decrease in average realized prices primarily in Texas due to lower hedged
power prices
Lower energy margins due to increased supply cost on load contracts
Lower capacity margins on contract expirations and lower demand in South Central business
Lower gross margin due to lower gas generation driven by the current mothball status of Gregory in Texas
Lower gross margin due to a 24% decrease in ISO capacity prices and a 76% decrease in volume
Higher gross margin due to a 17% increase in coal generation mainly in Texas driven by the timing of planned
and unplanned outages
Other
Decrease in economic gross margin
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open
positions related to economic hedges
Decrease in contract and emission credit amortization
Increase in gross margin
East/West Region
Lower gross margin from commercial optimization activities
Lower gross margin due to a decrease in generation driven by lower economic generation due to milder
weather conditions and the Will County outage
Lower gross margin due to lower load contracted prices coupled with slightly lower volumes
Lower gross margin due to a lower cost of market adjustment for fuel oil inventory
Lower gross margin by BETM due to higher gains in 2016 on over the counter strategies, offset in small part by
higher gains in 2017 congestion strategies
Other
Decrease in economic gross margin
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open
positions related to economic hedges
Increase in contract and emission credit amortization
Decrease in gross margin
(In millions)
$
$
(315)
(48)
(27)
(17)
(14)
68
(5)
(358)
499
(2)
139
(In millions)
$
$
$
(59)
(54)
(28)
(33)
(20)
6
(188)
22
1
(165)
Retail gross margin and economic gross margin
The following is a discussion of gross margin and economic gross margin for Retail.
(In millions except otherwise noted)
Retail revenue
Supply management revenue
Capacity revenues
Customer mark-to-market
Contract amortization
Other
Operating revenue (a)
Cost of sales (b)
Mark-to-market for economic hedging activities
Contract amortization
Gross margin
Less: Mark-to-market for economic hedging activities, net
Less: Contract and emission credit amortization
Economic gross margin
Business Metrics
Mass electricity sales volume (GWh) - Gulf Coast
Mass electricity sales volume (GWh) - All other regions
C&I electricity sales volume (GWh) All regions (c)
Natural gas sales volumes (MDth)
Average Retail Mass customer count (in thousands)
Ending Retail Mass customer count (in thousands)
$
$
$
Years ended December 31,
2017
2016
$
$
$
6,115
187
83
(4)
(1)
—
6,380
(4,768)
181
—
1,793
177
(1)
1,617
36,169
6,221
20,400
3,212
2,863
2,876
6,100
154
82
—
(1)
—
6,335
(4,687)
365
(6)
2,007
365
(7)
1,649
35,102
6,764
18,906
2,199
2,778
2,818
(a)
(b)
(c)
Includes intercompany sales of $5 million and $4 million in 2017 and 2016, respectively, representing sales from Retail to the Gulf Coast region.
Includes intercompany purchases of $1,035 million and $850 million in 2017 and 2016, respectively.
Includes volumes for 2017 for one customer that self-supplied their volumes for all of 2016 versus only two months in 2017.
Retail gross margin decreased $214 million and economic gross margin decreased $32 million for the year ended
December 31, 2017, compared to the same period in 2016, due to:
Lower gross margin due to lower rates to customers driven by customer product, term, and mix of $103
million or approximately $1.60 per MWh, partially offset by lower supply costs of $28 million or
approximately $0.50 per MWh driven primarily by a decrease in power prices at the time of procurement
Lower gross margin due to milder weather conditions in 2017 as compared to 2016 resulting in a reduction in
load of 350,000 MWh
Lower gross margin related to the impact of Hurricane Harvey in 2017, driven by $9 million due to a
reduction in load of 200,000 MWh, and the unfavorable impact of selling back excess supply along with $7
million of customer relief
Higher gross margin driven by higher average customer counts of 85,000 along with higher average usage due
to customer mix
Decrease in economic gross margin
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open
positions related to economic hedges
Increase in contract and emission credit amortization
Decrease in gross margin
Renewables gross margin and economic gross margin
(In millions)
$
$
$
(75)
(11)
(16)
70
(32)
(188)
6
(214)
Renewables gross margin increased $17 million and economic gross margin increased $22 million for the year ended
December 31, 2017, compared to the same period in 2016, primarily driven by new distributed generation solar projects placed
in service, increased margin in operations and maintenance agreements which focus on servicing NRG Yield assets and receipt
of insurance proceeds offsetting lower volume at the Ivanpah solar plant.
72
73
NRG Yield gross margin and economic gross margin
NRG Yield gross margin decreased $22 million and economic gross margin decreased $28 million for the year ended
December 31, 2017, compared to the same period in 2016, primarily due to a 5% decrease in volume generated at our Alta Wind
and NRG Wind TE Holdco projects, due to lower wind resources.
Mark-to-market for Economic Hedging Activities
Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow
hedges. Total net mark-to-market results increased by $327 million during the year ended December 31, 2017, compared to the
same period in 2016.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows:
Generation
Gulf
Coast
East/
West
Year Ended December 31, 2017
Retail
Renewables
Elimination (a)
Total
(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized losses/
(gains) on settled positions related to economic hedges
$
107
$
(40) $
(2) $
1
$
64
$
(35)
5
(2)
(13)
154
$
72
$
(35) $
(4) $
(12)
$
218
$
130
109
239
Net unrealized (losses)/gains on open positions related to
economic hedges
Total mark-to-market gains/(losses) in operating
revenues
Mark-to-market results in operating costs and
expenses
Reversal of previously recognized unrealized gains on
settled positions related to economic hedges
Net unrealized (losses)/gains on open positions related to
economic hedges
Total mark-to-market (losses)/gains in operating costs
and expenses
(a) Represents the elimination of the intercompany activity between Retail and Generation.
$
(17) $
(1) $
(1) $
— $
(64) $
(83)
(3)
12
182
—
(154)
37
$
(20) $
11
$
181
$
— $
(218) $
(46)
Year Ended December 31, 2016
Generation
Gulf
Coast
East/
West
Retail
Renewables
(In millions)
NRG
Yield
Elimination(a)
Total
Mark-to-market results in operating
revenues
Reversal of previously recognized unrealized
(gains)/losses on settled positions related to
economic hedges
Net unrealized (losses)/gains on open positions
related to economic hedges
Total mark-to-market losses in operating
revenues
Mark-to-market results in operating costs
and expenses
Reversal of previously recognized unrealized
losses/(gains) on settled positions related to
economic hedges
Reversal of acquired gain positions related to
economic hedges
Net unrealized gains/(losses) on open positions
related to economic hedges
Total mark-to-market gains in operating
costs and expenses
$
(389) $
(89) $
(2) $
— $
— $
33
$
(447)
(129)
41
2
(6)
—
(103)
(195)
$
(518) $
(48) $
— $
(6) $
— $
(70) $
(642)
$
31
$
16
$
305
$
— $
— $
(33) $
319
—
40
(12)
(2)
—
60
—
—
—
—
—
103
$
71
$
2
$
365
$
— $
— $
70
$
(12)
201
508
(a) Represents the elimination of the intercompany activity between Retail and Generation.
Mark-to-market results consist of unrealized gains and losses on contacts that are yet to be settled. The settlement of these
transactions is reflected in the same revenue or cost caption as the items being hedged.
The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date.
For the year ended December 31, 2017, the $239 million gain in operating revenues from economic hedge positions was
driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period and an
increase in value of open positions as a result of decreases in gas prices. The $46 million loss in operating costs and expenses
from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that
settled during the period partially offset by an increase in the value of open positions as a result of increases in ERCOT heat rate.
In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of
energy commodities for the years ended December 31, 2017 and 2016. The realized and unrealized financial and physical trading
results are included in operating revenue. The Company's trading activities are subject to limits within the Company's Risk
Management Policy and are primarily transacted through BETM.
(In millions)
Trading gains/(losses)
Realized
Unrealized
Total trading gains
Year ended December 31,
2017
2016
$
$
43
(11)
32
$
$
71
28
99
74
75
Operations and Maintenance Expense
Depreciation and Amortization
Generation
Gulf Coast
East/West
Retail
Renewables
NRG
Yield
Corporate Eliminations
Total
(In millions)
Generation
Retail
Renewables
NRG
Yield
Corporate
Total
(In millions)
Year Ended December 31, 2017
Year Ended December 31, 2016
$
$
515
577
$
$
371
488
$
$
222
245
$
$
118
122
$
$
196
176
$
$
15
27
$
$
(44) $
(36) $
1,393
1,599
Year Ended December 31, 2017
Year Ended December 31, 2016
$
$
377
516
$
$
117
111
$
$
196
185
$
$
334
303
$
$
32
57
$
$
1,056
1,172
Operations and maintenance expenses decreased by $206 million for the year ended December 31, 2017, compared to the
same period in 2016, due to the following:
Depreciation and amortization expense decreased by $116 million for the year ended December 31, 2017, compared to the
same period in 2016, due to the Jewett Mine being fully depreciated in December 2016 as well as impairments in 2016.
(In millions)
Impairment Losses
Decrease in operation and maintenance expenses due to major maintenance activities and environmental
control work at Midwest Generation offset by higher variable operating costs
Decrease in operations and maintenance expenses due to timing of planned outages in Texas
Decrease in operations and maintenance expenses due to lower expenses at Big Cajun II in 2017
Decrease in operations and maintenance expenses due to the deactivation of the Huntley and Dunkirk facilities
in 2016
Decrease in Retail operation and maintenance expenses due to reduced headcount
Decrease in operations and maintenance expense due to a reduction in headcount related to the sale of the
engine services business
Operations and maintenance expense increased due to forced outages at Walnut Creek and El Segundo in 2017
Other
Other Cost of Operations
$
$
(96)
(32)
(24)
(18)
(22)
(10)
20
(24)
(206)
Generation
Gulf Coast
East/West
Retail
Renewables
NRG
Yield
Corporate
Total
For the year ended December 31, 2017, the Company recorded impairment losses of $1,709 million related to various facilities
as further described in Item 15 — Note 10, Asset Impairments and Note 11, Goodwill and Other Intangibles, to the Consolidated
Financial Statements.
In 2016, the Company recorded impairment losses of $702 million related to various facilities, as well as goodwill for its
Texas reporting units, as further described in Item 15 — Note 10, Asset Impairments and Note 11, Goodwill and Other Intangibles,
to the Consolidated Financial Statements.
Selling, General and Administrative Expenses
Year Ended December 31, 2017
Year Ended December 31, 2016
$
$
207
265
$
$
452
498
$
$
(In millions)
56
61
$
$
22
17
$
$
170
254
$
$
907
1,095
Generation
Retail
Renewables
NRG Yield
Corporate
Total
Selling, general and administrative expenses decreased by $188 million for the year ended December 31, 2017 compared
to the same period in 2016. The decrease in year over year expenses is due primarily to a reduction in personnel costs and
selling and marketing activities as the Company continues to focus on cost management.
(In millions)
Reorganization Costs
Year Ended December 31, 2017
Year Ended December 31, 2016
$
$
101
95
$
$
76
66
$
$
100
93
$
$
21
20
$
$
67
65
$
$
— $
1
$
365
340
Other cost of operations, increased by $25 million for the year ended December 31, 2017, compared to the same period in
2016.
Increase in asset retirement expenses of $18 million in the East, offset by a reduction in property taxes at
Huntley and Dunkirk
Increase in expense due to a $10 million sales tax audit settlement received in 2016, offset slightly by a
decrease in gross receipt taxes in 2017
Increase of $14 million in reclamation expenses at the Jewett Mine, offset by favorable tax assessments related
to coal plants in Texas
Other
(In millions)
$
$
10
7
4
4
25
Reorganization costs of $44 million, primarily related to employee costs were incurred as part of the Transformation Plan
announced in 2017.
Other Income - Affiliate
Other income - affiliate represents the services fees charged to GenOn for shared services under the Services Agreement
through the June 14, 2017, the date of deconsolidation.
Gain/(Loss) on Sale of Assets
During the year ended December 31, 2017, the Company sold land and certain wind assets which resulted in gains of $16
million. During the year ended December 31, 2016, the Company sold a majority interest in its EVgo business to Vision Ridge
Partners, which resulted in a loss on sale as described in Item 15 — Note 3, Discontinued Operations, Acquisitions and Dispositions,
to the Consolidated Financial Statements.
Impairment Losses on Investments
For the year ended December 31, 2017, the Company recorded other-than-temporary impairment losses of $79 million,
which is primarily due to an other-than-temporary impairment of the Company's investment in Petra Nova Parish Holdings, as
further described in Item 15 — Note 10, Asset Impairments, to the Consolidated Financial Statements.
For the year ended December 31, 2016, the Company recorded other-than-temporary impairment losses of $268 million,
which is primarily due to other-than-temporary impairments on the Company's interests in Petra Nova Parish Holdings, Sherbino
and Community Wind North, as further described in Item 15 — Note 10, Asset Impairments, to the Consolidated Financial
Statements.
76
77
Loss on Debt Extinguishment
Income from Discontinued Operations, Net of Income Tax
For the year ended December 31, 2017, NRG recorded loss from discontinued operations, net of income tax (benefit)/expense
of $789 million, related to GenOn, as further described in Item 15 — Note 3, Discontinued Operations, Acquisitions and
Dispositions.
For the year ended December 31, 2016, NRG recorded income from discontinued operations, net of income tax (benefit)/
expense of $92 million, related to GenOn, as further described in Item 15 — Note 3, Discontinued Operations, Acquisitions and
Dispositions.
Net loss attributable to noncontrolling interests and redeemable noncontrolling interests
Net loss attributable to noncontrolling interests and redeemable noncontrolling interests was $184 million for the year ended
December 31, 2017, compared to $117 million for the year ended December 31, 2016. For the years ended December 31, 2017,
and 2016, the net losses attributable to noncontrolling interests primarily reflect losses allocated to tax equity investors using the
hypothetical liquidation at book value, or HLBV, method, offset in part by NRG Yield, Inc.'s share of income for the period.
A loss on debt extinguishment of $53 million was recorded for the year ended December 31, 2017, primarily driven by the
redemption of NRG Senior Notes at a price above par value.
A loss on debt extinguishment of $142 million was recorded for the year ended December 31, 2016, primarily driven by the
repurchase of NRG Senior Notes at a price above par value and the write-off of the unamortized debt issuance costs related to the
replacement of the 2018 Term Loan Facility with the new 2023 Term Loan Facility.
Income Tax Expense
For the year ended December 31, 2017, NRG recorded income tax expense of $8 million on a pre-tax loss of $1,540 million.
For the same period in 2016, NRG recorded income tax expense of $5 million on a pre-tax loss of $978 million. The effective
tax rate was (0.5)% and (0.5)% for the years ended December 31, 2017 and 2016, respectively.
For the year ended December 31, 2017, NRG's overall effective tax rate was different than the statutory rate of 35% primarily
due to tax expense recorded from the revaluation of the existing net deferred tax asset and state taxes, partially offset by the change
in valuation allowance, establishing the AMT credit receivable and the generation of PTC's from various wind facilities. The tax
expense recorded for revaluation of the net deferred tax asset is required to reflect the reduction in the corporate income tax rate
from 35% to 21% in accordance with the Tax Act.
Year Ended December 31,
2017
2016
(In millions
except as otherwise stated)
Loss before income taxes
$
(1,540)
$
Tax at 35%
State taxes
Foreign operations
Tax Act - corporate income tax rate change
Valuation allowance due to corporate income tax rate change
Valuation allowance - current period activities
Impact of non-taxable entity earnings
Book goodwill impairment
Net interest accrued on uncertain tax positions
Production tax credits
Recognition of uncertain tax benefits
Tax expense attributable to consolidated partnerships
State rate change including true-up to current period activity
AMT refundable credit
Other
Income tax expense
Effective income tax rate
(539)
19
2
733
(660)
482
(5)
30
—
(20)
(5)
4
18
(64)
13
8
(0.5)%
$
$
(978)
(342)
—
10
—
—
398
22
—
1
(26)
2
(1)
(59)
—
—
5
(0.5)%
The effective income tax rate may vary from period to period depending on, among other factors, the geographic and business
mix of earnings and losses and changes in valuation allowances in accordance with ASC 740, Income Taxes, or ASC 740. These
factors and others, including the Company's history of pre-tax earnings and losses, are taken into account in assessing the ability
to realize deferred tax assets.
78
79
Consolidated Results of Operations for the years ended 2016 and 2015
Gross Margin
The following table provides selected financial information for the Company:
(In millions except otherwise noted)
Operating Revenues
Energy revenue (a)
Capacity revenue (a)
Retail revenue
Mark-to-market for economic hedging activities
Contract amortization
Other revenues (b)
Total operating revenues
Operating Costs and Expenses
Cost of sales (a)
Mark-to-market for economic hedging activities
Contract and emissions credit amortization (c)
Operations and maintenance
Other cost of operations
Total cost of operations
Depreciation and amortization
Impairment losses
Selling, general and administrative
Development costs
Total operating costs and expenses
Other income - affiliate
Loss on sale of assets
Gain on postretirement benefits curtailment
Operating Income/(Loss)
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates
Impairment losses on investments
Other income, net
Loss on sale of equity method investment
Net (loss)/gain on debt extinguishment
Interest expense
Total other expense
Loss from Continuing Operations Before Income Taxes
Income tax expense
Net Loss from Continuing Operations
Income/(loss) from discontinued operations, net of tax
Net Loss
Less: Net loss attributable to noncontrolling interests and redeemable
noncontrolling interests
Net Loss Attributable to NRG Energy, Inc.
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)
Includes realized gains and losses from financially settled transactions.
(a)
(b) Includes unrealized trading gains and losses.
(c) Includes amortization of SO2 and NOx credits and excludes amortization of RGGI.
$
$
$
Year Ended December 31,
2016
2015
Change
$
3,131
1,225
6,357
(642)
(56)
497
10,512
5,827
(508)
43
1,599
340
7,301
1,172
702
1,095
89
10,359
193
(80)
—
266
27
(268)
34
—
(142)
(895)
(1,244)
(978)
5
(983)
92
(891)
3,867
1,361
6,867
(134)
(40)
407
12,328
6,870
59
41
1,657
373
9,000
1,351
4,860
1,228
154
16,593
193
—
21
(4,051)
36
(56)
26
(14)
10
(937)
(935)
(4,986)
1,345
(6,331)
(105)
(6,436)
$
(736)
(136)
(510)
(508)
(16)
90
(1,816)
1,043
567
(2)
58
33
1,699
179
4,158
133
65
6,234
—
(80)
(21)
4,317
(9)
(212)
8
14
(152)
42
(309)
4,008
1,340
5,348
197
5,545
(63)
5,608
(117)
(774) $
(54)
(6,382) $
2.46
$
2.66
(8)%
The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of sales,
which includes cost of fuel, other costs of sales, contract and emission credit amortization and mark-to-market for economic
hedging activities.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin,
which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the
GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a
substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic
gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors
as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined
as the sum of energy revenue, capacity revenue and other revenue, less cost of fuels and other cost of sales.
Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract
amortization, emission credit amortization, or other operating costs.
The tables below present the composition and reconciliation of gross margin and economic gross margin which reflects the
Company's current view of reporting segments for the years ended December 31, 2016 and 2015:
Year Ended December 31, 2016
Generation
Gulf
Coast
East/
West
Subtotal
Retail
Renewables
NRG
Yield
Corporate/
Eliminations
Total
$ 2,073
$ 1,098
$ 3,171
$
— $
369
$
Mark-to-market for economic hedging activities
(518)
(In millions except otherwise noted)
Energy revenue
Capacity revenue
Retail revenue
Contract amortization
Other revenue (a)
Operating revenue
Cost of fuel
Other costs of sales(b)
Mark-to-market for economic hedging
activities
Contract and emission credit amortization
293
—
15
237
598
—
(48)
—
85
2,100
1,733
(938)
(387)
71
(29)
(469)
(299)
2
(5)
891
—
(566)
15
322
—
6,336
—
(1)
—
3,833
(1,407)
6,335
(8)
(686)
(4,679)
73
(34)
365
(6)
—
—
(6)
(1)
44
406
(3)
(11)
—
—
Gross margin
$
817
$
962
$ 1,779
$ 2,007
$
392
$
968
$
Less: Mark-to-market for economic hedging
activities, net
Less: Contract and emission credit amortization,
net
(447)
(46)
(493)
365
(14)
(5)
(19)
(7)
(6)
(1)
—
(75)
Economic gross margin
$ 1,278
$ 1,013
$ 2,291
$ 1,649
$
399
$ 1,043
$
Business Metrics
MWh sold (thousands)(c)(d)
MWh generated (thousands)(e)
52,929
47,828
25,995
17,114
3,827
3,827
7,363
9,264
(a) Renewables Other revenue includes $19 million of intercompany revenue to NRG Yield.
(b) Includes purchased energy, capacity and emissions credits.
(c) MWh sold excludes generation at facilities in the West and NRG Yield that generate revenue under tolling agreements.
(d) Does not include MWh of 71 thousand or MWt of 1,966 thousand for thermal sold by NRG Yield.
(e) Does not include MWh of 275 thousand or MWt of 1,966 thousand for thermal generated by NRG Yield.
582
345
—
—
(69)
177
$
(991) $
(11)
21
(70)
—
(46)
1,035
(1,097)
(33)
(28)
—
(6)
3,131
1,225
6,357
(642)
(56)
497
10,512
(1,321)
(4,506)
508
(43)
$
5,150
(134)
(99)
$
5,383
130
898
70
3
4
—
3
1
80
81
(In millions except otherwise noted)
Energy revenue
Capacity revenue
Retail revenue
Mark-to-market for economic hedging activities
Contract amortization
Other revenue (a)
Operating revenue
Cost of fuel
Other costs of sales(b)
Mark-to-market for economic hedging
activities
Contract and emission credit amortization
Year Ended December 31, 2015
Generation
Gulf
Coast
East/
West
Subtotal
Retail
Renewables
NRG
Yield
Corporate/
Eliminations
Total
$ 2,443
$ 1,629
$ 4,072
$
— $
356
$
290
—
(66)
15
207
2,889
(1,137)
(355)
(17)
(28)
737
—
(76)
—
—
2,290
(715)
(442)
(29)
(7)
1,027
—
(142)
15
207
5,179
(1,852)
—
6,910
4
(1)
—
6,913
(9)
(797)
(5,236)
(46)
(35)
(4)
(6)
—
—
(3)
—
30
383
(4)
(12)
—
—
495
341
—
(2)
(54)
188
968
(43)
(28)
—
—
$
(1,056) $
(7)
(43)
9
—
(18)
(1,115)
152
959
(9)
—
3,867
1,361
6,867
(134)
(40)
407
12,328
(1,756)
(5,114)
(59)
(41)
Gross margin
$ 1,352
$ 1,097
$ 2,449
$ 1,658
$
367
$
897
$
(13) $
5,358
Less: Mark-to-market for economic hedging
activities, net
Less: Contract and emission credit amortization,
net
(83)
(105)
(188)
(13)
(7)
(20)
—
(7)
(3)
—
(2)
(54)
—
—
(193)
(81)
Economic gross margin
$ 1,448
$ 1,209
$ 2,657
$ 1,665
$
370
$
953
$
(13) $
5,632
Business Metrics
MWh sold (thousands)(c)(d)
MWh generated (thousands)(e)
58,127
54,162
37,403
24,623
3,685
3,739
6,760
9,247
(a) Renewables Other revenue includes $11 million of intercompany revenue to NRG Yield.
(b) Includes purchased energy, capacity and emissions credits.
(c) MWh sold excludes generation at facilities in the West and NRG Yield that generate revenue under tolling agreements.
(d) Does not include MWh of 297 thousand or MWt of 1,946 thousand for thermal sold by NRG Yield.
(e) Does not include MWh of 297 thousand or MWt of 1,946 thousand for thermal generated by NRG Yield.
The table below represents the weather metrics for 2016 and 2015:
Years ended
December 31,
Quarter ended
December 31,
Quarter ended
September 30,
Quarter ended
June 30,
Quarter ended
March 31,
Weather Metrics
Gulf
Coast(b)
East/West
Gulf
Coast(b)
East/West
Gulf
Coast(b)
East/West
Gulf
Coast(b)
East/West
Gulf
Coast(b)
East/West
2016
CDDs(a)
HDDs(a)
2015
CDDs
HDDs
10 year average
CDDs
HDDs
2,967
1,529
2,870
1,887
2,897
1,928
1,169
3,190
1,223
3,322
1,028
3,556
362
545
286
556
240
754
71
1,145
107
1,029
65
1,233
1,655
—
1,652
—
1,597
4
806
23
798
16
688
49
873
53
892
47
969
77
273
410
293
390
259
448
76
931
41
1,285
90
1,092
19
1,613
25
1,887
16
1,827
(a) National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the
mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that
the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the
CDDs/HDDs for each day during the period.
(b) CDDs/HDDs for the Gulf Coast region represent an average of cumulative population-weighted CDDs/HDDs for Texas and the West South-Central Climate
region.
Generation gross margin and economic gross margin
Generation gross margin decreased $670 million and economic gross margin decreased $366 million, both of which include
intercompany sales, during the year ended December 31, 2016, compared to the same period in 2015.
The tables below describe the decrease in Generation gross margin and economic gross margin:
Gulf Coast Region
Lower gross margin resulting from lower average realized energy prices due to a decline in natural gas prices
and increased wind generation in Texas
Lower gross margin primarily due to 11% lower coal generation and 21% lower gas generation in Texas, which
was driven by lower gas prices, increased wind generation in Texas, an increase in unplanned outages and
timing of planned outages
Higher gross margin resulting from a 12% increase in nuclear generation driven by reduced unplanned outages
and the timing of planned outages
Other
Decrease in economic gross margin
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open
positions related to economic hedges
Decrease in contract and emission credit amortization
Decrease in gross margin
East/West Region
Lower gross margin due to a 24% decrease in generation primarily driven by the environmental control work at
Powerton and fuel conversion projects at Joliet
Lower gross margin due to decreased realized capacity prices in New York due to a change in the mix of
capacity resources and a 15% decrease in PJM cleared auction prices
Lower gross margin due to the deactivation of the Huntley and Dunkirk facilities as well as the sale of the
Rockford
Lower gross margin due to lower contracted volumes
Lower gross margin due to a decrease in realized energy prices due to the decline in natural gas prices
Lower gross margin due to a 7% decrease in resource adequacy capacity volumes sold in California due to unit
retirements and a 4% decrease in price
Higher gross margin by BETM due to higher gains in 2016 on over the counter strategies
Changes in commercial optimization activities
Other
Decrease in economic gross margin
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open
positions related to economic hedges
Increase in contract and emission credit amortization
Decrease in gross margin
(In millions)
$
(148)
(82)
55
5
(170)
(364)
(1)
(535)
$
$
(In millions)
$
(141)
(79)
(66)
(12)
(12)
(10)
88
50
(14)
(196)
59
2
(135)
$
$
82
83
Retail gross margin and economic gross margin
Renewables gross margin and economic gross margin
Years ended December 31,
2016
2015
Renewables gross margin increased $25 million and economic gross margin increased $29 million for the year ended
December 31, 2016, compared to the same period in 2015, primarily driven by a 15% increase in generation at both the Mountain
Wind I and II facilities, a 4% increase in generation at the Ivanpah solar plant and generation from the Guam solar plant that
reached COD in the third quarter of 2015.
The following is a discussion of gross margin and economic gross margin for Retail.
(In millions except otherwise noted)
Retail revenue
Supply management revenue
Capacity revenues
Customer mark-to-market
Contract amortization
Other
Operating revenue (a)
Cost of sales (b)
Mark-to-market for economic hedging activities
Contract amortization
Gross margin
Less: Mark-to-market for economic hedging activities, net
Less: Contract and emission credit amortization
Economic gross margin
Business Metrics
Mass electricity sales volume (GWh) - Gulf Coast
Mass electricity sales volume (GWh) - All other regions
C&I electricity sales volume (GWh) All regions
Natural gas sales volumes (MDth)
Average Retail Mass customer count (in thousands)
Ending Retail Mass customer count (in thousands)
$
$
$
$
$
$
6,100
154
82
—
(1)
—
6,335
(4,687)
365
(6)
2,007
365
(7)
1,649
25,102
6,674
18,906
2,199
2,778
2,818
6,629
165
116
4
(1)
—
6,913
(5,245)
(4)
(6)
1,658
—
(7)
1,665
34,600
8,090
19,342
1,901
2,775
2,755
(a)
(b)
Includes intercompany sales of $4 million and $3 million in 2016 and 2015, respectively, representing sales from Retail to the Gulf Coast region.
Includes intercompany purchases of $850 million and $895 million in 2016 and 2015, respectively.
Retail gross margin increased $350 million and economic gross margin decreased $15 million for the year ended
December 31, 2016, compared to the same period in 2015, due to:
Higher gross margin due to lower supply costs of $452 million or approximately $7.00 per MWh driven by a
decrease in natural gas prices, partially offset by lower rates to customers of $431 million or approximately
$6.50 per MWh
Lower gross margin of $19 million due to the unfavorable impact of selling back excess supply and $3 million
in lower margin from a reduction in load of 86,000 MWhs due to milder weather conditions in 2016 as
compared to 2015
Lower gross margin due to lower volumes driven by lower average customer usage and mix
Decrease in economic gross margin
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open
positions related to economic hedges
Increase in gross margin
$
$
$
21
(22)
(14)
(15)
365
350
NRG Yield gross margin and economic gross margin
NRG Yield gross margin increased $71 million and economic gross margin increased $90 million for the year ended
December 31, 2016, compared to the same period in 2015, primarily related to a 26% increase in volume generated at Alta wind
projects as well as an increase in price per MWh at Alta X and XI wind projects as the PPAs began in January 2016 compared to
merchant prices in 2015.
Mark-to-market for Economic Hedging Activities
Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow
hedges. Total net mark-to-market results increased by $59 million in the year ended December 31, 2016, compared to the same
period in 2015.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region are as follows:
Generation
Year Ended December 31, 2016
Gulf Coast
East/West
Retail
Renewables
NRG Yield
Elimination(a)
Total
(In millions)
Mark-to-market results in operating
revenues
Reversal of previously recognized
unrealized (gains)/losses on settled
positions related to economic hedges
Net unrealized (losses)/gains on open
positions related to economic hedges
Total mark-to-market losses in operating
revenues
and expenses
Reversal of previously recognized
unrealized losses/(gains) on settled
positions related to economic hedges
Reversal of acquired gain positions related
to economic hedges
Net unrealized gains/(losses) on open
positions related to economic hedges
Total mark-to-market gains in operating
costs and expenses
$
$
$
(389) $
(89) $
(2) $
— $
— $
33
$
(447)
(129)
41
2
(6)
—
(103)
(195)
(518) $
(48) $ — $
(6) $
— $
(70) $
(642)
31
$
16
$
305
$
— $
— $
(33) $
319
—
40
(12)
(2)
—
60
—
—
—
—
—
103
(12)
201
$
71
$
2
$
365
$
— $
— $
70
$
508
(a) Represents the elimination of the intercompany activity between Retail and Generation.
(In millions)
Mark-to-market results in operating costs
84
85
Generation
Year Ended December 31, 2015
Gulf Coast
East/West
Retail
Renewables
NRG Yield
Elimination(a)
Total
(In millions)
Operations and Maintenance Expense
Generation
Gulf Coast
East/West
Retail
Renewables
NRG
Yield
Corporate Eliminations
Total
(In millions)
Year Ended December 31, 2016
Year Ended December 31, 2015
$
$
577
654
$
$
488
487
$
$
245
225
$
$
122
96
$
$
176
180
$
$
27
25
$
$
(36) $
(10) $
1,599
1,657
(408) $
(158) $
(1) $
(3) $
(2) $
45
$
(527)
Operations and maintenance expenses decreased by $58 million for the year ended December 31, 2016, compared to
the same period in 2015, due to the following:
342
82
(66) $
(76) $
5
4
—
—
(36)
393
$
(3) $
(2) $
9
$
(134)
Decrease in Gulf Coast operations and maintenance expense primarily related to the timing of planned outages
at the Texas coal plants and STP
Decrease in East operations and maintenance expense due to unit deactivations at Huntley, Dunkirk, and Will
County
34
$
3
$
373
$
— $
— $
(45) $
365
Decrease in West operations and maintenance expense primarily due to the retirement of the El Segundo
—
(51)
(18)
(14)
(4)
(373)
—
—
—
—
—
36
(22)
(402)
$
(17) $
(29) $
(4) $
— $
— $
(9) $
(59)
facility and lower operation and maintenance costs at Encina
Increase in East operations and maintenance expense due to the Joliet conversion project and environmental
control work at Midwest Generation, offset by lower variable operating costs due to the decreased generation
volumes.
Increase in Renewables operating costs due primarily to increased production at the Ivanpah solar plant,
Mountain Wind I and II facilities and the Guam solar plant which reached COD in the fourth quarter of 2015
Mark-to-market results in operating
revenues
Reversal of previously recognized
unrealized (gains)/losses on settled
positions related to economic hedges
Net unrealized gains/(losses) on open
positions related to economic hedges
Total mark-to-market (losses)/gains in
operating revenues
Mark-to-market results in operating
costs and expenses
Reversal of previously recognized
unrealized losses/(gains) on settled
positions related to economic hedges
Reversal of acquired gain positions related
to economic hedges
Net unrealized (losses)/gains on open
positions related to economic hedges
Total mark-to-market losses in operating
costs and expenses
$
$
$
(In millions)
$
$
(66)
(19)
(8)
20
9
6
(58)
Other
Other cost of operations
Generation
Gulf Coast
East/West
Retail
Renewables
(In millions)
NRG
Yield
Corporate
Total
Year Ended December 31, 2016
Year Ended December 31, 2015
$
$
95
94
$
$
66
74
$
$
93
112
$
$
20
21
$
$
65
72
$
$
1
$
— $
340
373
Other cost of operations, comprised of asset retirement expense, insurance expense and property tax expense, decreased
by $33 million for the year ended December 31, 2016, compared to the same period in 2015, primarily due to a decrease in
gross tax receipts taxes of $10 million related to lower retail revenue and $10 million favorable settlement of Texas sales tax
audit.
(a) Represents the elimination of the intercompany activity between Retail and Generation.
Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these
transactions is reflected in the same revenue or cost caption as the items being hedged.
The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date.
For the year ended December 31, 2016, the $642 million loss in operating revenues from economic hedge positions was
driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period and a decrease
in value of open positions as a result of increases in gas prices. The $508 million gain in operating costs and expenses from
economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled
during the period and an increase in the value of open positions as a result of increases in coal and gas prices partially offset by
the reversal of acquired contracts.
In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of
energy commodities for the years ended December 31, 2016 and 2015. The realized and unrealized financial and physical trading
results are included in operating revenues. The Company's trading activities are subject to limits within the Company's Risk
Management Policy.
Trading gains/(losses)
Realized
Unrealized
Total trading gains/(losses)
Year Ended December 31,
2016
2015
(In millions)
$
$
71
28
99
$
$
57
(76)
(19)
86
87
Depreciation and Amortization
Interest Expense
Generation
Retail
Renewables
NRG
Yield
Corporate
Total
(In millions)
NRG's interest expense decreased by $42 million for the year ended December 31, 2016, compared to the same period
in 2015, due to the following:
Year Ended December 31, 2016
Year Ended December 31, 2015
$
$
516
693
$
$
111
132
$
$
185
176
$
$
303
303
$
$
57
47
$
$
1,172
1,351
Depreciation and amortization expense decreased by $179 million for the year ended December 31, 2016, compared to the
same period in 2015, primarily due to a $116 million decrease related to the impairment of the Limestone and W.A. Parish facilities
located in the Gulf Coast region in 2015 and a $68 million decrease related to the impairment of the Dunkirk and Huntley facilities
located in the East region in 2015.
Impairment Losses
In 2016, the Company recorded impairment losses of $702 million related to various facilities, as well as goodwill for its
Texas reporting unit, as further described in Item 15 — Note 10, Asset Impairments and Note 11, Goodwill and Other Intangibles,
to the Consolidated Financial Statements.
In 2015, the Company recorded impairment losses of $4,860 million related to various facilities, as well as goodwill for its
Texas and Home Solar reporting units, as further described in Item 15 - Note 10, Asset Impairments and Note 11, Goodwill and
Other Intangibles, to the Consolidated Financial Statements.
Selling, General and Administrative Expenses
Year Ended December 31, 2016
Year Ended December 31, 2015
$
$
265
159
$
$
498
546
$
$
(In millions)
61
54
$
$
17
15
$
$
254
454
$
$
1,095
1,228
Generation
Retail
Renewables
NRG Yield
Corporate
Total
Selling, general and administrative expenses decreased by $133 million for the year ended December 31, 2016 compared
to the same period in 2015, primarily due to a decrease in advertising and the continued focus on cost management.
Development Costs
Development costs decreased by $65 million for the year ended December 31, 2016, compared to the same period in 2015,
due to the strategic decision for a more focused development program primarily related to Renewables and the sale of EVgo in
2016.
Loss on Sale of Assets
During the year ended December 31, 2016, the Company sold a majority interest in its EVgo business to Vision Ridge
Partners, which resulted in a loss on sale as described in Item 15 — Note 3, Discontinued Operations, Acquisitions and Dispositions,
to the Consolidated Financial Statements.
Impairment Losses on Investments
For the year ended December 31, 2016, the Company recorded other-than-temporary impairment losses of $268 million,
which is primarily due to other-than-temporary impairments on the Company's interests in Petra Nova Parish Holdings, Sherbino
and Community Wind North, as further described in Item 15 — Note 10, Asset Impairments, to the Consolidated Financial
Statements.
For the year ended December 31, 2015, the Company recorded other-than-temporary impairment losses on certain of its cost
and equity method investments of $56 million, as further described in Item 15 — Note 10, Asset Impairments, to the Consolidated
Financial Statements.
Loss on Debt Extinguishment
A loss on debt extinguishment of $142 million was recorded for the year ended December 31, 2016, primarily driven by the
repurchase of NRG senior notes at a price above par value and the write-off of the unamortized debt issuance costs related to the
replacement of the 2018 Term Loan Facility with the new 2023 Term Loan Facility.
Decrease due to the repurchases of Senior Notes at the end of 2015 and 2016
Decrease in derivative interest expense from changes in fair value of interest rate swaps
Decrease due to the redemption of outstanding bonds related to NRG Peakers Finance Company
Decrease due to the termination of Alta X and XI term loans and the related interest rate swaps in 2015
Increase due to the replacement of the 2018 Term Loan Facility with the 2023 Term Loan Facility
Increase due to the issuance of NRG Yield Inc. 3.25% Convertible Senior Notes due 2020 and NRG Yield
Operating LLC Revolving Credit Facility issued in 2015
Increase due to the issuance of NRG Yield Operating LLC 5.00% Senior Notes due 2026
Increase due to $200 million of debt issued by CVSR Holdco in August 2016
Other
Income Tax Expense
(In millions)
(40)
(19)
(8)
(6)
9
8
7
4
3
(42)
$
$
For the year ended December 31, 2016, NRG recorded an income tax expense of $5 million on a pre-tax loss of $978 million.
For the same period in 2015, NRG recorded an income tax expense of $1,345 million on pre-tax loss of $4,986 million. The
effective tax rate was (0.5)% and (27.0)% for the years ended December 31, 2016 and 2015, respectively.
For the year ended December 31, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily
due to recording of a valuation allowance on the federal and certain state net deferred tax assets that may not be realizable under
a “more likely than not” measurement. In addition, a portion of the book goodwill impairment is classified as a permanent reversal
impacting the effective tax rate.
(Loss) before income taxes
Tax at 35%
State taxes
Foreign operations
Federal and state tax credits, excluding PTCs
Valuation allowance - current period activities
Impact of non-taxable entity earnings
Book goodwill impairment
Net interest accrued on uncertain tax positions
Production tax credits
Recognition of uncertain tax benefits
Tax expense attributable to consolidated partnerships
State rate change including true-up to current period activity
Other
Income tax expense
Effective income tax rate
Year Ended December 31,
2016
2015
(In millions
except as otherwise stated)
$
$
(978)
(342)
—
10
—
398
22
—
1
(26)
2
(1)
(59)
—
5
(0.5)%
(4,986)
(1,745)
(215)
1
(5)
3,023
(10)
340
(3)
(33)
(15)
12
(7)
2
1,345
(27.0)%
$
$
The effective income tax rate may vary from period to period depending on, among other factors, the geographic and business
mix of earnings and losses and changes in valuation allowances in accordance with ASC 740. These factors and others, including
the Company's history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets.
88
89
Income/(Loss) from Discontinued Operations, Net of Income Tax
For the year ended December 31, 2016, NRG recorded income from discontinued operations, net of income tax (benefit)/
expense of $92 million related to GenOn, as further described in Item 15 — Note 3, Discontinued Operations, Acquisitions and
Dispositions.
For the year ended December 31, 2015, NRG recorded loss from discontinued operations, net of income tax (benefit)/expense
of $105 million related to GenOn, as further described in Item 15 — Note 3, Discontinued Operations, Acquisitions and Dispositions.
Net loss attributable to noncontrolling interests and redeemable noncontrolling interests
Net loss attributable to noncontrolling interests and redeemable noncontrolling interests was $117 million for the year ended
December 31, 2016, compared to $54 million for the year ended December 31, 2015. For the years ended December 31, 2016
and 2015, the net losses attributable to noncontrolling interests primarily reflect losses allocated to tax equity investors using the
hypothetical liquidation at book value, or HLBV, method, as well as NRG Yield, Inc.'s share of losses for the period.
Liquidity and Capital Resources
Liquidity Position
As of December 31, 2017 and 2016, NRG's liquidity, excluding collateral funds deposited by counterparties, was
approximately $3.2 billion and $2.4 billion, respectively, comprised of the following:
Cash and cash equivalents:
NRG excluding NRG Yield
NRG Yield and subsidiaries
Restricted cash - operating
Restricted cash - reserves (a)
Total
Total credit facility availability
Total liquidity, excluding collateral funds deposited by counterparties
(a)
Includes reserves primarily for debt service, performance obligations, and capital expenditures.
As of December 31,
2017
2016
(In millions)
$
$
843
148
71
437
1,499
1,711
3,210
$
$
621
317
56
390
1,384
989
2,373
For the year ended December 31, 2017, total liquidity, excluding collateral funds deposited by counterparties, increased by
$837 million. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow
Discussion. Cash and cash equivalents at December 31, 2017, were predominantly held in money market funds invested in treasury
securities, treasury repurchase agreements or government agency debt.
Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance
operating and maintenance capital expenditures, to fund dividends to NRG's common stockholders, and to fund other liquidity
commitments. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing
and investing activity within the dictates of prudent balance sheet management.
On July 12, 2017, NRG announced its Transformation Plan, which is described further in Item 1 — Business.
Credit Ratings
On October 6, 2017, Moody's upgraded the NRG rating outlook to positive from stable and affirmed NRG's Ba3 Corporate
Family Rating.
The following table summarizes the Company's current credit ratings:
NRG Energy, Inc.
6.25% Senior Notes, due 2022
6.25% Senior Notes, due 2024
7.25% Senior Notes, due 2026
6.625% Senior Notes, due 2027
5.75% Senior Notes, due 2028
Term Loan Facility, due 2023
NRG Yield, Inc.
5.375% NRG Yield Operating LLC Senior Notes, due 2024
5.00% NRG Yield Operating LLC Senior Notes, due 2026
S&P
BB- Stable
BB-
BB-
BB-
BB-
BB-
BB+
BB
BB
BB
Moody's
Ba3 Positive
B1
B1
B1
B1
B1
Baa3
Ba2
Ba2
Ba2
90
91
Sources of Liquidity
2023 Term Loan Facility
The principal sources of liquidity for NRG's future operating and capital expenditures are expected to be derived from cash
on hand, cash flows from operations, cash proceeds from future sales of assets, including sales to NRG Yield, Inc. and financing
arrangements. As described in Item 15 — Note 12, Debt and Capital Leases, to the Consolidated Financial Statements, the
Company's financing arrangements consist mainly of the Senior Credit Facility, the Senior Notes, the NRG Yield 2019 Convertible
Notes, the NRG Yield 2020 Convertible Notes, the Yield Operating 2020 senior unsecured notes, the NRG Yield, Inc. revolving
credit facility, and project-related financings.
Sale of Ownership in NRG Yield, Inc. and Renewables Platform
On February 6, 2018, NRG and Global Infrastructure Partners, or GIP, entered into a purchase and sale agreement for GIP
to purchase NRG's ownership in NRG Yield, Inc. and NRG's renewables platform for cash of $1.375 billion, subject to certain
adjustments. The purchase and sale agreement includes the sale of all of NRG's ownership in NRG Yield, Inc., NRG's renewable
energy development and operations platforms and NRG's renewable energy non-ROFO backlog and pipeline.
In connection with the transaction, the Company entered into a Consent and Indemnity Agreement with NRG Yield, Inc.
and GIP setting forth key terms and conditions of NRG Yield, Inc.'s consent to the transaction. As part of the Consent and Indemnity
Agreement, NRG has agreed to indemnify GIP and NRG Yield, Inc. and its project companies for any increase in property taxes
at the California-based solar projects resulting from the transaction.
The transaction is expected to close in the second half of 2018 and is subject to various customary closing conditions,
approvals and consents. Upon the closing of the transaction, NRG’s Ivanpah asset will no longer be part of the NRG Yield ROFO
assets.
On January 24, 2017, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to
LIBOR plus 2.25%, the LIBOR floor remains 0.75%. As a result of the repricing, the Company realized interest savings of
approximately $9 million in 2017 and expects approximately $60 million in interest savings over the life of the loan.
Issuance of 2028 Senior Notes
On December 7, 2017, NRG issued $870 million of aggregate principal amount at par of 5.75% senior unsecured notes due
2028. The 2028 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest
is paid semi-annually beginning on July 15, 2018, until the maturity date of January 15, 2028. The proceeds from the issuance of
the 2028 Senior Notes were utilized to redeem the Company's 6.625% Senior Notes due 2023.
Carlsbad Project Financing
On May 26, 2017, Carlsbad Energy Holdings LLC entered into a note payable agreement with financial institutions for the
issuance of up to $407 million of senior secured notes, that bear interest at a rate of 4.12%, and mature on October 31, 2038. As
of December 31, 2017, $407 million of these notes were outstanding.
Also on May 26, 2017, Carlsbad Energy Holdings, LLC entered into a credit agreement, or the Carlsbad Financing Agreement,
with the issuing banks, for a $194 million construction loan, that will convert to a term loan upon completion of the project. The
Carlsbad Financing Agreement also includes a letter of credit facility not to exceed an aggregate amount of $83 million, and a
working capital loan facility with an aggregate principal amount not to exceed $4 million. As of December 31, 2017, $20 million
was outstanding under the construction loan and $29 million in letters of credit in support of the project were issued.
Sale of South Central Business
Asset Dispositions
On February 6, 2018, NRG and Cleco Energy LLC, or Cleco, entered into a purchase and sale agreement for Cleco to purchase
NRG's South Central business for cash of $1.0 billion, subject to certain adjustments. The transaction is expected to close in the
second half of 2018 and is subject to various customary closing conditions, approvals and consents. The South Central business
owns and operates a 3,555 MW portfolio of generation assets in the Gulf Coast region. Upon the closing of the transaction, NRG
will enter into a sale leaseback agreement for the Cottonwood plant through May 2025.
Sale of BETM
On February 23, 2018, the Company entered into an agreement to sell BETM to a third party for $70 million. The transaction
is expected to close in the second half of 2018 and is subject to various customary closing conditions, approvals and consents.
Sale of Assets to NRG Yield, Inc.
On February 6, 2018, the Company entered into an agreement with NRG Yield, Inc. to sell 100% of the membership interests
in Carlsbad Energy Holdings LLC, which owns the Carlsbad project, a 527 MW natural gas fired project in Carlsbad, CA, pursuant
to the ROFO Agreement. The purchase price for the transaction is $365 million in cash consideration, subject to customary working
capital and other adjustments. The transaction is expected to close during the fourth quarter of 2018.
On January 24, 2018, the Company entered into an agreement with NRG Yield, Inc. to sell 100% of its ownership interest
in Buckthorn Solar for cash consideration of $42 million, subject to other adjustments. The transaction is expected to close during
the first quarter of 2018.
On November 1, 2017, NRG completed the sale of a 38 MW solar portfolio primarily comprised of assets from SPP funds,
in addition to other projects developed by NRG, to NRG Yield, Inc. for cash consideration of $71 million, plus $3 million in
working capital adjustments.
On August 1, 2017, NRG closed on its sale of the remaining 25% interest in NRG Wind TE Holdco, a portfolio of 12 wind
projects, to NRG Yield, Inc. for total cash consideration of $44 million. The transaction also includes potential additional payments
to NRG dependent on actual energy prices for merchant periods beginning in 2027.
On March 27, 2017, the Company sold (i) a 16% interest in the Agua Caliente solar project, representing ownership of
approximately 46 net MW of capacity and (ii) NRG's interests in seven utility-scale solar projects located in Utah representing
265 net MW of capacity which have reached commercial operations to NRG Yield, Inc. NRG Yield, Inc. paid cash consideration
of $130 million, plus $1 million in working capital adjustments, and assumed non-recourse project debt of approximately $328
million.
During the year ended December 31, 2017, the Company received proceeds of $87 million, primarily related to the
sale of certain equipment, sale of certain Minnesota wind assets and the sale of the Crawford site.
First Lien Structure
NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets
acquired in the GenOn and EME (including Midwest Generation) acquisitions, assets held by NRG Yield, Inc. and NRG's assets
that have project-level financing. NRG uses the first lien structure to reduce the amount of cash collateral and letters of credit
that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements
for forward sales of power or gas used as a proxy for power. To the extent that the underlying hedge positions for a counterparty
are out-of-the-money to NRG, the counterparty would have claim under the first lien program. The first lien program limits the
volume that can be hedged, not the value of underlying out-of-the-money positions. The first lien program does not require NRG
to post collateral above any threshold amount of exposure. Within the first lien structure, the Company can hedge up to 80% of
its coal and nuclear capacity and 10% of its other assets with these counterparties for the first 60 months and then declining
thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for
the first lien to be available to that counterparty. The first lien structure is not subject to unwind or termination upon a ratings
downgrade of a counterparty and has no stated maturity date.
The Company's first lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices.
As of December 31, 2017, all hedges under the first liens were in-the-money on a counterparty aggregate basis.
The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a percentage
relative to the Company's coal and nuclear capacity under the first lien structure as of December 31, 2017:
Equivalent Net Sales Secured by First Lien Structure (a)
In MW
As a percentage of total net coal and nuclear capacity (b)
(a) Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region.
(b) Net coal and nuclear capacity represents 80% of the Company's total coal and nuclear assets eligible under the first lien, which excludes coal assets
acquired in the GenOn and EME (including Midwest Generation) acquisitions, assets in NRG Yield, Inc. and NRG's assets that have project-level
financing.
719
13%
—
—%
—
—%
2018
2019
2020
2021
—
—%
92
93
Uses of Liquidity
Debt Service Obligations
The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized
by the following: (i) commercial operations activities; (ii) debt service obligations, as described more fully in Item 15 — Note 12, Debt
and Capital Leases, to the Consolidated Financial Statements; (iii) capital expenditures, including repowering and renewable
development, and environmental; and (iv) allocations in connection with acquisition opportunities, debt repayments, return of capital
and dividend payments to stockholders, as described in Item 15 — Note 15, Capital Structure, to the Consolidated Financial Statements.
Restructuring Support Agreement
As described in Note 3, Discontinued Operations, Acquisitions and Dispositions, NRG, the GenOn Entities and certain holders
of the GenOn and GenOn Americas Generation Senior Notes entered into a Restructuring Support Agreement that provides for a
restructuring and recapitalization of GenOn through a prearranged plan of reorganization. Certain principal terms of the Restructuring
Support Agreement include that NRG will provide settlement consideration to GenOn of $261.3 million, which will be paid in cash
less any amounts owed to NRG under the intercompany secured revolving credit facility. As of June 30, 2017, GenOn owed NRG
approximately $125 million under the intercompany secured revolving credit facility. NRG agreed to provide GenOn with a letter of
credit facility during the pendency of the Chapter 11 Cases, to be utilized for required letters of credit in lieu of the intercompany
secured revolving credit facility. GenOn can no longer utilize the intercompany secured revolving credit facility and, on July 27, 2017,
the letter of credit facility was terminated, as GenOn has obtained a separate letter of credit facility with a third party financial institution.
In addition, NRG will retain the pension liability for GenOn employees for service provided prior to the completion of the reorganization.
GenOn’s net pension liability as of December 31, 2017, was approximately $92 million. NRG will also retain the liability for GenOn’s
post-employment and retiree health and welfare benefits, in an amount up to $25 million, which was recorded as a liability as of
December 31, 2017.
Commercial Operations
The Company's commercial operations activities require a significant amount of liquidity and capital resources. These liquidity
requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to
participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (i.e. buying fuel before receiving
energy revenues); (iv) initial collateral for large structured transactions; and (v) collateral for project development. As of December 31,
2017, commercial operations had total cash collateral outstanding of $187 million and $515 million outstanding in letters of credit to
third parties primarily to support its commercial activities for both wholesale and retail transactions. As of December 31, 2017, total
collateral held from counterparties was $38 million in cash and $17 million of letters of credit.
Future liquidity requirements may change based on the Company's hedging activities and structures, fuel purchases, and future
market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements are dependent
on the Company's credit ratings and general perception of its creditworthiness.
2017 Senior Note Redemptions
During the year ended December 31, 2017, the Company redeemed $1.5 billion in aggregate principal of its Senior Notes for
$1.5 billion, which included accrued interest of $29 million. In connection with the redemptions, a $49 million loss on debt
extinguishment was recorded, which included the write-off of previously deferred financing costs of $7 million. In addition, the
Company expects to save approximately $55 million in annualized interest, after consideration of the issuance of the 2028 Senior Note.
Amount in millions, except rates
7.625% senior notes due 2018
7.875% senior notes due 2021
6.625% senior notes due 2023
Total
(a) Includes payment for accrued interest.
Principal
Repurchased
Cash Paid (a)
Average Early Redemption
Percentage
$
$
398
206
869
1,473
$
$
411
218
915
1,544
101.42%
102.63%
103.57%
Principal payments on debt and capital leases as of December 31, 2017 are due in the following periods:
Description
Recourse Debt:
Senior notes, due 2022
Senior notes, due 2024
Senior notes, due 2026
Senior notes, due 2027
Senior notes, due 2028
Term loan facility, due 2023
Tax-exempt bonds
Subtotal Recourse Debt
Non-Recourse Debt:
NRG Yield Operating LLC Senior Notes, due 2024
NRG Yield Operating LLC Senior Notes, due 2026
NRG Yield Inc. Convertible Senior Notes, due 2019
NRG Yield Inc. Convertible Senior Notes, due 2020
Yield LLC and Yield Operating LLC Revolving Credit Facility, due
2019
El Segundo Energy Center, due 2023
Marsh Landing, due 2023
Alta Wind I-V lease financing arrangements, due 2034 and 2035
Walnut Creek, term loans due 2023
Utah Portfolio, due 2022
Tapestry, due 2021
CVSR, due 2037
CVSR Holdco, due 2037
Alpine, due 2022
Energy Center Minneapolis, due 2025 and 2031
Viento, due 2023
NRG Yield Other
Subtotal NRG Yield debt (non-recourse to NRG) (a)
Ivanpah, due 2033 and 2038
Carlsbad Energy Project (a)
Agua Caliente, due 2037
Agua Caliente Borrower 1, due 2038
Cedro Hill, due 2029 (a)
Midwest Generation, due 2019
NRG Other Renewables (a)
NRG Other
Subtotal other non-recourse debt
Subtotal all non-recourse debt
Subtotal long-term debt
Capital Leases:
Capital leases
Subtotal Capital Leases
Total Debt and Capital Leases
2018
2019
2020
2021
(In millions)
2022
Thereafter
Total
$
— $
— $
— $
— $
992
$
— $
—
—
—
—
19
—
19
—
—
—
—
—
48
55
40
45
12
11
26
6
8
7
16
32
306
41
—
32
3
12
103
166
9
366
672
691
4
4
695
$
$
—
—
—
—
19
—
19
—
—
345
—
55
49
57
42
47
13
11
24
6
8
11
18
36
—
—
—
—
19
—
19
—
—
—
288
—
53
60
43
49
14
11
21
6
8
11
15
77
—
—
—
—
19
—
19
—
—
—
—
—
57
62
45
52
13
129
23
7
8
11
16
32
722
656
455
42
19
33
3
12
49
24
9
191
913
932
1
1
933
$
44
1
34
3
12
—
27
9
130
786
805
—
—
805
$
45
—
35
3
12
—
27
10
132
587
606
—
—
606
—
—
—
—
19
—
1,011
—
—
—
—
—
63
65
47
55
226
—
25
9
103
11
17
33
654
47
—
35
3
13
—
83
8
733
1,000
1,250
870
1,777
465
6,095
500
350
—
—
—
130
19
709
19
—
—
627
160
—
157
81
369
3,121
854
407
649
74
90
—
320
135
992
733
1,000
1,250
870
1,872
465
7,182
500
350
345
288
55
400
318
926
267
278
162
746
194
135
208
163
579
5,914
1,073
427
818
89
151
152
647
180
189
843
1,854
2,529
5,650
3,537
9,451
11,745
16,633
—
—
5
—
$ 1,854
$
—
11,745
5
$16,638
(a) Debt associated with the asset sales announced in February 2018.
In addition to the debt and capital leases shown in the above table, NRG had issued $733 million of letters of credit under the
Company's $2.5 billion Revolving Credit Facility as of December 31, 2017.
94
95
Capital Expenditures
The following table and descriptions summarize the Company's capital expenditures for maintenance, environmental, and
growth investments, for the year ended December 31, 2017, and the estimated capital expenditure and growth investments forecast
for 2018.
Generation
Gulf Coast
East/West (a)
Retail
Renewables
NRG Yield
Corporate
Total cash capital expenditures for the year ended
December 31, 2017
Funding from debt financing, net of fees
Other investments(b)
Total capital expenditures and investments, net of financings
Estimated capital expenditures for 2018 (c)
Funding from debt financing, net of fees
Other investments(b)
Estimated capital expenditures for 2018, net of financings
Maintenance
Environmental
Growth
Investments
Total
(In millions)
$
$
$
$
95
22
29
5
27
15
193
—
—
193
221
—
—
221
$
$
$
$
1
24
—
—
—
—
25
—
—
25
3
—
—
3
$
$
$
$
4
321
52
506
4
6
893
(1,076)
267
84
500
(391)
86
195
$
$
$
$
100
367
81
511
31
21
1,111
(1,076)
267
302
724
(391)
86
419
(a) Includes International
(b) Other investments include restricted cash activity and acquisitions
(c) Maintenance capital expenditures includes approximately $66 million related to announced asset sales
• Environmental capital expenditures — For the year ended December 31, 2017, the Company's environmental capital
expenditures included the final payments for DSI/ESP upgrades at the Powerton facility and the Joliet gas conversion to
satisfy CPS.
• Growth Investments capital expenditures — For the year ended December 31, 2017, the Company's growth investment
capital expenditures included $414 million for solar projects, $324 million for repowering projects, $93 million for wind
projects, and $62 million for the Company's other growth projects.
Environmental Capital Expenditures Estimate
NRG estimates that environmental capital expenditures from 2018 through 2022 required to comply with environmental
laws will be approximately $82 million, which includes $14 million for Midwest Generation. These costs are primarily associated
with the cost of complying with anticipated CCR requirements and NOx Controls.
The table below summarizes the status of NRG's coal fleet with respect to air quality controls. Planned investments are
either in construction or budgeted in the existing capital expenditures budget. Changes to regulations could result in changes to
planned installation dates. NRG uses an integrated approach to fuels, controls and emissions markets to meet environmental
standards.
Units
State
Control
Equipment
Install
Date
Control
Equipment
Install
Date
Control
Equipment
Install
Date
Control
Equipment
Install Date
SO2
NOx
Mercury
Particulate
Big Cajun II 1
Big Cajun II 2
Big Cajun II 3
Conemaugh 1-2
Indian River 4
Keystone 1-2
Limestone 1-2
Powerton 5
Powerton 6
W.A. Parish 5, 6, 7
W.A. Parish 8(a)
Waukegan 7
Waukegan 8
Will County 4
LA
LA
LA
PA
DE
PA
TX
IL
IL
TX
TX
IL
IL
IL
DSI
Gas
Conversion
PAL
FGD
CDS
FGD
FGD
DSI
DSI
FF co-
benefit
FGD
DSI
DSI
DSI
2015
2015
2013
LNBOFA/
SNCR
LNBOFA/
SNCR
LNBOFA/
SNCR
2005/2014
ACI
2004/2014
Gas
Conversion
2002/2014
ACI
2015
2015
2015
ESP/upgrade
1981/2015
Gas
Conversion
2015
ESP/upgrade
1983/2015
1994, 95
SCR
2014
FGD/ESP/
SCR
1994,95/
2014
ESP
1970, 1971
LNBOFA/
SCR
1999/2011
ACI/CDS/FF
2008/2011
ESP/FF
1980/2011
SCR
2003
FGD/ESP/
SCR
2011
2009
2016
2014
1988
1982
1985-86
LNBOFA
2002/2022
OFA/SNCR
2003/2012
OFA/SNCR
2002/2012
SCR
SCR
2004
2004
2002
2014
LNBOFA
2015
LNBOFA
1999
2017
LNBOFA/
SNCR
1999,2001/
2012
ACI
ACI
ACI
ACI
ACI
ACI
ACI
ACI
2003
2015
2009
2009
2015
2015
ESP
ESP
1967, 1968
1985-1986
ESP/upgrade
1973/2016
ESP/upgrade
1976/2014
FF
FF
2008
ESP/upgrade
2008
ESP/upgrade
2009
ESP/upgrade
1988
1988
1958/2002,
2014
1962/1999,
2015
1963,72/
2000
(a) Unit expected to be converted into a cogeneration facility to provide power and steam to the Petra Nova CCF.
ACI - Activated Carbon Injection
CDS - Circulating Dry Scrubber
DSI - Dry Sorbent Injection with Trona
ESP - Electrostatic Precipitator
FGD - Flue Gas Desulfurization (wet)
FF- Fabric Filter
LNBOFA - Low NOx Burner with Overfire Air
OFA - Overfire Air
PAL - Plantwide Applicability Limit
SCR - Selective Catalytic Reduction
SNCR - Selective Non-Catalytic Reduction
The following table summarizes the estimated environmental capital expenditures for the referenced periods by region:
2018
2019
2020
2021
2022
Total
Gulf Coast
East
(excluding
MWG)
MWG
Total
$
$
— $
7
4
3
7
21
$
(In millions)
3
2
—
23
19
47
$
$
— $
1
7
6
—
14
$
3
10
11
32
26
82
NRG's current contracts with the Company's rural electrical customers in the Gulf Coast region allow for recovery of a
portion of the region's capital costs once in operation, along with a capital return incurred by complying with any change in law,
including interest over the asset life of the required expenditures. The actual recoveries will depend, among other things, on the
timing of the completion of the capital projects and the remaining duration of the contracts.
96
97
Common Stock Dividends
The following table lists the dividends paid during 2017:
Cash Flow Discussion
2017 compared to 2016
Fourth Quarter
2017
Third Quarter
2017
Second
Quarter 2017
First Quarter
2017
The following table reflects the changes in cash flows for the comparative years:
Dividends per Common Share
$
0.030
$
0.030
$
0.030
$
0.030
On January 19, 2018, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, or $0.12 per
share on an annualized basis, payable on February 15, 2018, to stockholders of record as of February 1, 2018. The Company's
common stock dividends are subject to available capital, market conditions, and compliance with associated laws and regulations.
The Company expects that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable
future.
Share Repurchases
The Company’s board of directors has authorized the repurchase of up to $1 billion of the Company's common stock, with
the first $500 million program to begin in the first quarter of 2018. Following completion of the initial program, and as NRG
progresses towards the closing of the announced asset sales, the Company expects to execute the remaining $500 million of the
$1 billion share repurchase program.
Fuel Repowerings
Carlsbad —The Company is currently overseeing construction of the Carlsbad project, which when completed will consist
of approximately 527 MWs of net generation capacity. On February 6, 2018, the Company entered into an agreement with NRG
Yield, Inc. to sell the Carlsbad project pursuant to the ROFO Agreement. The transaction is expected to close during the fourth
quarter of 2018.
Canal 3 — The Company is currently overseeing construction of the Canal 3 project, a dual-fueled peaking facility, which
when completed will consist of approximately 333 MWs of net generating capacity. In January 2018, Final Notice To Proceed
was issued, and construction commenced with an anticipated COD by summer 2019. Under a cooperation agreement with GenOn,
GenOn has the right to purchase the project from NRG until March 31, 2018.
Puente Power Project — On October 5, 2017, the California Energy Commission, or CEC, the agency responsible for
permitting the Puente Power Project, issued a statement on behalf of the committee of two Commissioners overseeing the permitting
process stating their intention to issue a proposed decision that would deny a permit for the Puente Power Project. On October 16,
2017, NRG filed a motion to suspend the permitting proceeding for at least six months, which was granted on November 3, 2017.
During the six month suspension period, which could be extended, NRG will evaluate the progress of a procurement process
initiated by SCE to replace the Puente Power Project.
(In millions)
Net cash provided by operating activities
Net cash used by investing activities
Net cash used by financing activities
Net Cash Provided By Operating Activities
Year ended December 31,
2017
2016
Change
$
$
1,387
(1,066)
(485)
$
2,088
(792)
(915)
(701)
(274)
430
Changes to net cash provided by operating activities were driven by:
(In millions)
Changes in cash collateral in support of risk management activities due to changes in commodity prices
$
Other changes in working capital
Decrease in operating income adjusted for non-cash items
Increase in accounts receivable due to the timing of cash receipts
Decrease in prepaid expenses and total current assets due to reduced spending
Decrease in inventory as a result of initiatives related to the Transformation Plan
Cash provided by discontinued operations
Increase in accounts payable as a result of initiatives related to the Transformation Plan
Net Cash Used By Investing Activities
Changes to net cash used by investing activities were driven by:
$
(478)
(284)
(172)
(92)
56
72
81
116
(701)
Change in discontinued operations cash primarily related to the sale of the Aurora, Shelby and Seward in 2016
Decrease in capital expenditures related to environmental projects at Powerton and Joliet, as well as a decrease
in maintenance capital expense in our generation businesses, offset by an increase in growth capital
expenditures related to our solar and repowering projects
Decrease in cash grants received in 2017
Increase in other investments
Increase in investments in unconsolidated affiliates related primarily to investments in the utility-scale solar
portfolio
Other
Proceeds from sale of assets
Net increase in nuclear decommissioning trust fund activity due to a decrease in purchases of securities
Proceeds from sale of emissions allowances
Decrease in cash paid for acquisitions in 2017 compared to 2016 primarily due to acquisition of assets from
SunEdison in 2016
(In millions)
$
(350)
(135)
(28)
(17)
(17)
(6)
14
30
67
168
$
(274)
98
99
Net Cash Used By Financing Activities
2016 compared to 2015
Changes in net cash used by financing activities were driven by:
The following table reflects the changes in cash flows for the comparative years:
(In millions)
Net decrease in borrowings, Increase in borrowings, primarily related to Agua Caliente Borrower 1 & 2, 2038
Senior Notes and the Carlsbad project financing as well as reduced payments due to repurchases of Senior
Notes in 2016 as compared to 2017
$
Increase in cash contributions, net of distributions from noncontrolling interest primarily due to tax equity
financing
Change due to repurchase of preferred stock in 2016
Decrease in debt extinguishment costs due to fewer debt repurchases in 2017 as compared to 2016
Decrease in payment of dividends, due to the annualized dividend rate being reduced from $0.58/share to
$0.12/share in the first quarter of 2016
Change in debt issuance costs is primarily due to the refinancing of the senior credit facility and the issuance of
the 2026 and 2027 Senior Notes in 2016
Payment for affiliate receivable - GenOn
Change in discontinued operations cash related to an increase in long term deposits and financing fees in 2017
Other
$
303
251
226
79
38
26
(125)
(364)
(4)
430
(In millions)
Net cash provided by operating activities
Net cash used by investing activities
Net cash used by financing activities
Net Cash Provided By Operating Activities
Changes to net cash provided by operating activities were driven by:
Year ended December 31,
2016
2015
Change
$
$
2,088
(792)
(915)
$
1,349
(1,528)
(432)
739
736
(483)
Change in cash collateral in support of risk management activities
Decrease in accounts payable primarily related to lower operations and maintenance expense in 2016
Decrease in inventory primarily related to plant fuel conversions at Joliet and Unit 2 at the Big Cajun II facility
and deactivations of the Huntley and Dunkirk facilities
Other changes in working capital driven by various timing differences
Cash used by discontinued operations
Increase in accounts receivable due to timing of receipts
Decrease in accrued interest primarily driven by redemption of Senior Notes in late 2015 and 2016
Increase in prepaid expense primarily related to timing of property tax and insurance payments that occurred in
the first half of the year, and state tax receivables
Decrease in operating income adjusted for non-cash items
Net Cash Used By Investing Activities
Changes to net cash used by investing activities were driven by:
(In millions)
$
$
766
141
130
54
(181)
(120)
(27)
(23)
(1)
739
(In millions)
Cash provided by discontinued operations
Decrease in investments in unconsolidated affiliates in 2016 compared to 2015, primarily related to the 25%
investment in Desert Sunlight of $285 million, as well as, Petra Nova and Altenex in 2015
$
Proceeds from the sale of assets related to the majority interest sale of EVgo and the sale of real property at the
Potrero generating station in 2016
Decrease in capital expenditures, primarily related to environmental projects at the Powerton and Joliet
facilities
Insurance proceeds primarily related to the Cottonwood generation station outage in 2016
Increase in cash paid for acquisitions in 2016 compared to 2015
Decrease in cash grants received as the final Ivanpah cash grant amount was received in 2015 after resolution of
all open inquiries
Net decrease in nuclear decommissioning trust fund activity due to increase in purchases of securities in Q4
2016
Net decrease in emission allowances activity
Other
$
556
361
72
53
27
(178)
(46)
(43)
(42)
(24)
736
100
101
Net Cash Used By Financing Activities
Changes in net cash used by financing activities were driven by:
Repurchases of treasury stock in 2015
Cash provided by discontinued operations
Decrease in payment of dividends which reflects the reduction to the annualized dividend rate in 2016 from
$0.58/share to $0.12/share
Decrease in cash contributions from noncontrolling interest in 2016, primarily related to the NRG Yield, Inc.
public offering in 2015 which had proceeds of $599 million
Repurchase of preferred stock in 2016
Increase in debt extinguishment costs
Increase in debt issuance costs primarily due to the refinancing of the senior credit facility and the issuance of
the 2026 and 2027 Senior Notes
Net decrease in borrowings, offset by debt payments, which includes debt repurchases in 2016
Decrease in settlement of financing element related to acquired derivatives
Other
(In millions)
$
$
437
195
125
(803)
(226)
(121)
(68)
(23)
(8)
9
(483)
NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740
As of December 31, 2017, the Company had domestic pre-tax book loss of $1,557 million and foreign pre-tax book income
of $17 million. For the year ended December 31, 2017, the Company generated an NOL of $630 million due to a current year
taxable loss. As of December 31, 2017, the Company has cumulative domestic federal NOL carryforwards of $2.8 billion, which
will begin expiring in 2026 and cumulative state NOL carryforwards of $2.2 billion for financial statement purposes. In addition,
NRG has cumulative foreign NOL carryforwards of $224 million, which do not have an expiration date. As a result of the
Company's tax position, including the benefit of a worthless stock deduction of $9.5 billion upon GenOn emerging from bankruptcy
and upon evaluation of the Tax Cuts and Jobs Act potential impact on taxable income and based on current forecasts, the Company
anticipates income tax payments, primarily due to state and local jurisdictions, of up to $20 million in 2018.
The Company has recorded a long term receivable of $64 million representing refundable alternative minimum tax credits
from the IRS, net of sequestration, which are anticipated to be received from 2019 through 2022 pursuant to the 50% annual
limitation as enacted by the Tax Act upon repeal of corporate AMT effective January 1, 2018.
In addition to these amounts, the Company has $30 million of tax effected uncertain tax benefits for which the Company
has recorded a non-current tax liability of $33 million until such final resolution with the related taxing authority. The $33 million
non-current tax liability for uncertain tax benefits is from positions taken on various state returns, including accrued interest.
The Company is no longer subject to U.S. federal income tax examinations for years prior to 2015. With few exceptions,
state and local income tax examinations are no longer open for years before 2010.
Off-Balance Sheet Arrangements
Obligations under Certain Guarantee Contracts
NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial
transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt
guarantees, surety bonds and indemnifications. See also Item 15 — Note 26, Guarantees, to the Consolidated Financial Statements
for additional discussion.
Retained or Contingent Interests
NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity
Variable interest in Equity investments — As of December 31, 2017, NRG has several investments with an ownership interest
percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting.
Several of these investments are variable interest entities for which NRG is not the primary beneficiary.
NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $606 million as of
December 31, 2017. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG.
See also Item 15 — Note 16, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Consolidated
Financial Statements for additional discussion.
102
103
Contractual Obligations and Commercial Commitments
Fair Value of Derivative Instruments
NRG has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements
in addition to the Company's capital expenditure programs. The following tables summarize NRG's contractual obligations and
contingent obligations for guarantees. See also Item 15 — Note 12, Debt and Capital Leases, Note 22, Commitments and
Contingencies, and Note 26, Guarantees, to the Consolidated Financial Statements for additional discussion.
NRG may enter into power purchase and sales contracts, fuel purchase contracts and other energy-related financial
instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at generation
facilities or retail load obligations. In addition, in order to mitigate interest rate risk associated with the issuance of the Company's
variable rate and fixed rate debt, NRG enters into interest rate swap agreements.
Contractual Cash Obligations
Long-term debt (including estimated interest)
Capital lease obligations (including estimated
interest)
Operating leases
Fuel purchase and transportation obligations
Fixed purchased power commitments
Pension minimum funding requirement (b)
Other postretirement benefits minimum funding
requirement (c)
Other liabilities (d)
Total
By Remaining Maturity at December 31,
2017
Under
1 Year
1-3 Years
3-5 Years
Over
5 Years
Total (a)
2016 Total
(In millions)
$
1,521
$
3,315
$
3,913
$ 14,738
$ 23,487
$ 24,863
4
79
527
21
29
7
75
1
157
338
26
48
16
151
—
138
215
21
42
16
116
—
707
296
—
86
35
309
5
1,081
1,376
68
205
74
651
7
982
1,476
87
375
80
917
$
2,263
$
4,052
$
4,461
$ 16,171
$ 26,947
$ 28,787
(a) Excludes $30 million non-current payable relating to NRG's uncertain tax benefits under ASC 740 as the period of payment cannot be reasonably
estimated. Also excludes $771 million of asset retirement obligations which are discussed in Item 15 — Note 13, Asset Retirement Obligations, to the
Consolidated Financial Statements.
(b) These amounts represent the Company's estimated minimum pension contributions required under the Pension Protection Act of 2006. These amounts
represent estimates that are based on assumptions that are subject to change.
(c) These amounts represent estimates that are based on assumptions that are subject to change. The minimum required contribution for years after 2027 are
currently not available.
Includes water right agreements, service and maintenance agreements, stadium naming rights, LTSA commitments and other contractual obligations.
(d)
Guarantees
Letters of credit and surety bonds(a)
Asset sales guarantee obligations
Other guarantees
Total guarantees
By Remaining Maturity at December 31,
2017
Under
1 Year
1-3 Years
3-5 Years
Over
5 Years
Total
2016 Total
$
$
1,467
—
—
1,467
$
$
66
—
32
98
$
$
(In millions)
7
257
—
264
$
$
93
55
613
761
$
$
1,633
312
645
2,590
$
$
1,837
677
253
2,767
(a) Excludes $92 million and $272 million of letters of credit issued under the intercompany revolving credit agreement between NRG and GenOn as of
December 31, 2017 and 2016, respectively.
NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts
are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized
in earnings.
The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair
value in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. Specifically, these tables disaggregate
realized and unrealized changes in fair value; disaggregate estimated fair values at December 31, 2017, based on their level within
the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at December 31, 2017. For a full discussion
of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Item 15 — Note 4, Fair
Value of Financial Instruments, to the Consolidated Financial Statements.
Derivative Activity (Losses)/Gains
Fair value of contracts as of December 31, 2016
Contracts realized or otherwise settled during the period
Derivatives reclassified to held for sale
Changes in fair value
Fair value of contracts as of December 31, 2017
(In millions)
$
(128)
37
(14)
151
46
Fair Value of Contracts as of December 31, 2017
Maturity
$
Fair value hierarchy (Losses)/Gains
1 Year or Less
Greater Than 1
Year to 3 Years
Greater Than 3
Years to 5
Years
(In millions)
Greater Than
5 Years
Total Fair
Value
Level 1
Level 2
Level 3
Total
$
$
(22) $
98
(5)
71
$
(41) $
49
(6)
2
$
(3) $
—
(6)
(9) $
— $
(3)
(15)
(18) $
(66)
144
(32)
46
The Company has elected to disclose derivative assets and liabilities on a trade-by-trade basis and does not offset amounts
at the counterparty master agreement level. Also, collateral received or posted on the Company's derivative assets or liabilities are
recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-
current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed
in Item 7A — Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, NRG measures the sensitivity
of the Company's portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of
loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which
limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the
Company's derivative assets and liabilities, the net derivative assets and liability position is a better indicator of NRG's hedging
activity. As of December 31, 2017, NRG's net derivative asset was $46 million, an increase to total fair value of $174 million as
compared to December 31, 2016. This increase was primarily driven by gains in fair value and roll off trades that were settled
during the period, partially offset by derivatives reclassified to held for sale.
Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices
across the term of the derivative contracts would result in an increase of approximately $64 million in the net value of derivatives
as of December 31, 2017.
The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of the derivative contracts would result
in a decrease of approximately $67 million in the net value of derivatives as of December 31, 2017.
104
105
Critical Accounting Policies and Estimates
Derivative Instruments
NRG's discussion and analysis of the financial condition and results of operations are based upon the Consolidated Financial
Statements, which have been prepared in accordance with GAAP. The preparation of these financial statements and related
disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as
the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related
disclosures of contingent assets and liabilities. The application of these policies involves judgments regarding future events,
including the likelihood of success of particular projects, legal and regulatory challenges, and the fair value of certain assets and
liabilities. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying
assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant
effect, not only on the operation of the business, but on the results reported through the application of accounting measures used
in preparing the financial statements and related disclosures, even if the nature of the accounting policies have not changed.
On an ongoing basis, NRG evaluates these estimates, utilizing historic experience, consultation with experts and other
methods the Company considers reasonable. In any event, actual results may differ substantially from the Company's estimates.
Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are
recorded in the period in which the information that gives rise to the revision becomes known.
NRG's significant accounting policies are summarized in Item 15 — Note 2, Summary of Significant Accounting Policies,
to the consolidated financial statements. The Company identifies its most critical accounting policies as those that are the most
pervasive and important to the portrayal of the Company's financial position and results of operations, and that require the most
difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain.
Accounting Policy
Derivative Instruments
Income Taxes and Valuation Allowance for Deferred Tax Assets
Impairment of Long-Lived Assets and Investments
Goodwill and Other Intangible Assets
Contingencies
Judgments/Uncertainties Affecting Application
Assumptions used in valuation techniques
Assumptions used in forecasting generation
Assumptions used in forecasting borrowings
Market maturity and economic conditions
Contract interpretation
Market conditions in the energy industry, especially the
effects of price volatility on contractual commitments
Ability to be sustained upon audit examination of taxing
authorities
Interpret existing tax statute and regulations upon
application to transactions
Ability to utilize tax benefits through carry backs to prior
periods and carry forwards to future periods
Recoverability of investment through future operations
Regulatory and political environments and requirements
Estimated useful lives of assets
Environmental obligations and operational limitations
Estimates of future cash flows
Estimates of fair value
Judgment about impairment triggering events
Estimated useful lives for finite-lived intangible assets
Judgment about impairment triggering events
Estimates of reporting unit's fair value
Fair value estimate of intangible assets acquired in
business combinations
Estimated financial impact of event(s)
Judgment about likelihood of event(s) occurring
Regulatory and political environments and requirements
The Company follows the guidance of ASC 815 to account for derivative instruments. ASC 815 requires the Company to
mark-to-market all derivative instruments on the balance sheet and recognize changes in the fair value of non-hedge derivative
instruments immediately in earnings. In certain cases, NRG may apply hedge accounting to the Company's derivative instruments.
The criteria used to determine if hedge accounting treatment is appropriate are: (i) the designation of the hedge to an underlying
exposure; (ii) whether the overall risk is being reduced; and (iii) if there is a correlation between the changes in fair value of the
derivative instrument and the underlying hedged item. Changes in the fair value of derivatives instruments accounted for as hedges
are deferred and recorded as a component of OCI and subsequently recognized in earnings when the hedged transactions occur.
For purposes of measuring the fair value of derivative instruments, NRG uses quoted exchange prices and broker quotes.
When external prices are not available, NRG uses internal models to determine the fair value. These internal models include
assumptions of the future prices of energy commodities based on the specific market in which the energy commodity is being
purchased or sold, using externally available forward market pricing curves for all periods possible under the pricing model. In
order to qualify the derivative instruments for hedged transactions, NRG estimates the forecasted generation and forecasted
borrowings for interest rate swaps occurring within a specified time period. Judgments related to the probability of forecasted
generation occurring are based on available baseload capacity, internal forecasts of sales and generation, and historical physical
delivery on similar contracts. Judgments related to the probability of forecasted borrowings are based on the estimated timing of
project construction, which can vary based on various factors. The probability that hedged forecasted generation and forecasted
borrowings will occur by the end of a specified time period could change the results of operations by requiring amounts currently
classified in OCI to be reclassified into earnings, creating increased variability in the Company's earnings. These estimations are
considered to be critical accounting estimates.
Certain derivative instruments that meet the criteria for derivative accounting treatment also qualify for a scope exception
to derivative accounting, as they are considered to be NPNS. The availability of this exception is based upon the assumption that
NRG has the ability and it is probable to deliver or take delivery of the underlying item. These assumptions are based on available
baseload capacity, internal forecasts of sales and generation and historical physical delivery on contracts. Derivatives that are
considered to be NPNS are exempt from derivative accounting treatment and are accounted for under accrual accounting. If it is
determined that a transaction designated as NPNS no longer meets the scope exception due to changes in estimates, the related
contract would be recorded on the balance sheet at fair value combined with the immediate recognition through earnings.
Income Taxes and Valuation Allowance for Deferred Tax Assets
As of December 31, 2017, NRG had a valuation allowance of $1.8 billion. This amount is comprised of domestic federal
net deferred tax assets of approximately $1.5 billion, domestic state net deferred tax assets of $267 million, foreign net operating
loss carryforwards of $66 million, and foreign capital loss carryforwards of approximately $1 million. The Company believes it
is more likely than not that the results of future operations will not generate sufficient taxable income which includes the future
reversal of existing taxable temporary differences to realize deferred tax assets, requiring a valuation allowance to be recorded.
In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, which addresses how a company may recognize
provisional amounts for the effect of the changes related to the Tax Act. Consistent with that guidance, the Company recognized
provisional amounts based upon our interpretation of the tax laws and estimates which require significant judgments.
NRG continues to be under audit for multiple years by taxing authorities in other jurisdictions. Considerable judgment is
required to determine the tax treatment of a particular item that involves interpretations of complex tax laws including the impact
of the Tax Cuts and Jobs Act effective December 22, 2017. NRG is subject to examination by taxing authorities for income tax
returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia.
The Company is no longer subject to U.S. federal income tax examinations for years prior to 2015. With few exceptions,
state and local income tax examinations are no longer open for years before 2010.
106
107
Evaluation of Assets for Impairment and Other-Than-Temporary Decline in Value
The Company also recorded the following impairments in 2017 based on specific triggering events that occurred:
In accordance with ASC 360, Property, Plant, and Equipment, or ASC 360, NRG evaluates property, plant and equipment
and certain intangible assets for impairment whenever indicators of impairment exist. Examples of such indicators or events are:
•
•
Significant decrease in the market price of a long-lived asset;
Significant adverse change in the manner an asset is being used or its physical condition;
• Adverse business climate;
• Accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an
asset;
• Current period loss combined with a history of losses or the projection of future losses; and
• Change in the Company's intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will
be sold or disposed of before the end of its previously estimated useful life.
Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future
net cash flows expected to be generated by the asset, through considering project specific assumptions for long-term power pool
prices, escalated future project operating costs and expected plant operations. If such assets are considered to be impaired, the
impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the
assets by factoring in the probability weighting of different courses of action available to the Company. Generally, fair value will
be determined using valuation techniques such as the present value of expected future cash flows. NRG uses its best estimates in
making these evaluations and considers various factors, including forward price curves for energy, fuel costs and operating costs.
However, actual future market prices and project costs could vary from the assumptions used in the Company's estimates, and the
impact of such variations could be material.
For assets to be held and used, if the Company determines that the undiscounted cash flows from the asset are less than the
carrying amount of the asset, NRG must estimate fair value to determine the amount of any impairment loss. Assets held-for-sale
are reported at the lower of the carrying amount or fair value less the cost to sell. The estimation of fair value under ASC 360,
whether in conjunction with an asset to be held and used or with an asset held-for-sale, and the evaluation of asset impairment
are, by their nature, subjective. NRG considers quoted market prices in active markets to the extent they are available. In the
absence of such information, the Company may consider prices of similar assets, consult with brokers, or employ other valuation
techniques. NRG will also discount the estimated future cash flows associated with the asset using a single interest rate representative
of the risk involved with such an investment or employ an expected present value method that probability-weights a range of
possible outcomes. The use of these methods involves the same inherent uncertainty of future cash flows as previously discussed
with respect to undiscounted cash flows. Actual future market prices and project costs could vary from those used in the Company's
estimates, and the impact of such variations could be material.
Annually, during the fourth quarter, the Company revises its views of power and fuel prices including the Company's
fundamental view for long term prices, forecasted generation and operating and capital expenditures, in connection with the
preparation of its annual budget. Changes to the Company’s views of long term power and fuel prices impacted the Company’s
projections of profitability, based on management's estimate of supply and demand within the sub-markets for each plant and the
physical and economic characteristics of each plant. During the fourth quarter of 2017, the Company completed its annual budget
and revised its view of long-term power and fuel prices and the corresponding impact on estimated cash flows associated with its
long-lived assets. The most significant impact was a decrease in the Company’s long-term view of natural gas prices which resulted
in a reduction to long-term power prices and had a negative impact on the Company’s coal, nuclear and renewable facilities.
As a result, the following long-lived asset impairments were recorded during the fourth quarter of 2017, as further described
in Item 15 —Note 10, Asset Impairments, to the consolidated financial statements:
• South Texas Project, or STP - The Company recognized an impairment loss of $1,248 million related to its interest in
STP as a result of the decrease in the Company's view of long-term power prices in ERCOT.
• Indian River - The Company recognized an impairment loss of $36 million for Indian River as a result of the decrease
in the Company's view of long-term power prices in PJM.
• Keystone and Conemaugh - The Company recognized impairment losses of $35 million for Keystone and $35 million
for Conemaugh as a result of the decrease in the Company's view of long-term power prices in PJM.
• Wind Facilities - The Company recorded impairment losses of $110 million, $26 million and $4 million for Langford,
Elbow Creek and Forward, respectively, as a result of the decrease in the Company's view of long-term merchant power prices
in ERCOT and PJM. While Elbow Creek and Forward have contracts to sell power, the significant decrease in estimated power
prices had an impact on cash flows in post-contract periods.
• Bacliff Project - On June 16, 2017, NRG Texas Power LLC provided notice to BTEC New Albany, LLC that it was
exercising its right to terminate the Amended and Restated Membership Interest Purchase Agreement, or MIPA, due to the
Bacliff Project, a new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial
completion by the contractual expiration date of May 31, 2017. As a result of the MIPA termination, the Company recorded
an impairment loss of $41 million to reduce the carrying amount of the related construction in progress to zero during the second
quarter of 2017.
• Other Impairments - During the second, third and fourth quarters of 2017, the Company recorded impairment losses
of approximately $22 million, $14 million and $15 million, respectively, in connection with the Company's Renewables business.
These impairment losses were primarily to record the value of certain long-lived assets, including property, plant and equipment
and intangible assets, at fair market value at acquisition date or in connection with an impairment indicator.
NRG is also required to evaluate its equity method and cost method investments to determine whether or not they are impaired
in accordance with ASC 323, Investments - Equity Method and Joint Ventures, or ASC 323. The standard for determining whether
an impairment must be recorded under ASC 323 is whether a decline in the value is considered an other-than-temporary decline
in value. The evaluation and measurement of impairments under ASC 323 involves the same uncertainties as described for long-
lived assets that the Company owns directly and accounts for in accordance with ASC 360. Similarly, the estimates that NRG
makes with respect to its equity and cost-method investments are subjective, and the impact of variations in these estimates could
be material. Additionally, if the projects in which the Company holds these investments recognize an impairment under the
provisions of ASC 360, NRG would record its proportionate share of that impairment loss and would evaluate its investment for
an other-than-temporary decline in value under ASC 323. During the year ended December 31, 2016, the Company recorded
impairment losses on its equity method and cost method investments of $79 million due to other-than-temporary declines in value,
including the following:
During the fourth quarter of 2017, in connection with the preparation of the annual budget, management revised its view
of oil production expectations with respect to Petra Nova Parish Holdings. As a result, the Company reviewed its 50% interest
in Petra Nova Parish Holdings for impairment utilizing the other-than-temporary impairment model. In determining fair value,
the Company utilized an income approach and considered project specific assumptions for the future project cash flows. The
carrying amount of the Company's equity method investment exceeded the fair value of the investment and the Company
concluded that the decline is considered to be other-than-temporary. As a result, the Company measured the impairment loss
as the difference between the carrying amount and the fair value of the investment and recorded an impairment loss of $69
million.
Goodwill and Other Intangible Assets
At December 31, 2017, NRG reported goodwill of $539 million, consisting of $165 million associated with the acquisition
of EME, $341 million for retail business acquisitions, and $33 million associated with other business acquisitions.
The Company applies ASC 805, Business Combinations, or ASC 805, and ASC 350, to account for its goodwill and intangible
assets. Under these standards, the Company amortizes all finite-lived intangible assets over their respective estimated weighted-
average useful lives, while goodwill has an indefinite life and is not amortized. Goodwill and all intangible assets not subject to
amortization are tested for impairments at least annually, or more frequently whenever an event or change in circumstances occurs
that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The Company tests goodwill
for impairment at the reporting unit level, which is identified by assessing whether the components of the Company's operating
segments constitute businesses for which discrete financial information is available and whether segment management regularly
reviews the operating results of those components. The Company performs the annual goodwill impairment assessment as of
December 31 or when events or changes in circumstances indicate that the carrying value may not be recoverable. The Company
first assesses qualitative factors to determine whether it is more likely than not that impairment has occurred. In the absence of
sufficient qualitative factors, the Company performs a quantitative assessment by determining the fair value of the reporting unit
and comparing to its book value. If it is determined that the fair value of a reporting unit is below its carrying amount, where
necessary, the Company's goodwill will be impaired at that time.
The Company performed its qualitative assessment of macroeconomic, industry and market events and circumstances, and
the overall financial performance of the NRG Business Solutions (NRG Curtailment Solutions) and Retail Mass reporting units.
The Company determined it was not more likely than not that the fair value of the goodwill attributed to these reporting units were
less than their carrying amount and accordingly, no impairment existed for the year ended December 31, 2017.
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The Company performed a quantitative assessment for the reporting units in the following table. The Company determined
the fair value of these reporting units using primarily an income approach. Under the income approach, the Company estimated
the fair value of the reporting units' invested capital exceeds its carrying value and, as such, the Company concluded that goodwill
associated with the reporting units in the following table is not impaired as of December 31, 2017:
Recent Accounting Developments
See Item 15 — Note 2, Summary of Significant Accounting Policies, to the consolidated financial statements for a discussion
of recent accounting developments.
Reporting Unit
Midwest Generation (Generation Segment)
Texas Non-Commodity - excluding Goal Zero (Retail Segment)
Goal Zero (Retail Segment)
% Fair Value Over
Carrying Value
133%
325%
141%
The Company believes the methodology and assumptions used in its quantitative assessment are consistent with the views
of market participants. Significant inputs to the determination of fair value were as follows:
• The Company applied a discounted cash flow methodology to the long-term budgets for all of the plants in the region.
The significant assumptions used to derive the long-term budgets used in the income approach are affected by the following
key inputs:
The Company's views of power and fuel prices consider market prices for the first five-year period and the
Company's fundamental view for the longer term, which reflect the Company's long-term view of the price of
natural gas. The Company's fundamental view for the longer term reflects the implied power price and heat rate
that would support new build of a combined cycle gas plant. The price of natural gas plays an important role in
setting the price of electricity in many of the regions where NRG operates power plants. Hedging is included
to the extent of contracts already in place;
The Company's estimate of generation, fuel costs, capital expenditure requirements and the existing and
anticipated impact of environmental regulations;
The Company's fundamental view for the longer term, cash flows for the plants in the region were included in
the fair value calculation through the end of each plants' estimated useful life; and
Projected generation and resulting energy gross margin in the long-term budgets is based on an hourly dispatch
that simulates dispatch of each unit into the power market. The dispatch simulation is based on power prices,
fuel prices, and the physical and economic characteristics of each plant.
• The Company applied a discounted cash flow methodology to the long-term budgets for the Texas Non-Commodity and
Goal Zero reporting units. The significant assumptions used to derive the long-term budgets used in the income approach
are affected by the following key inputs: a terminal value utilizing assumed growth rates and discount rates that reflect
the inherent cash flow risk for each reporting unit.
During the fourth quarter of 2017, the Company concluded that BETM was held for sale in connection with board approval
and advanced negotiations to sell the business. Accordingly, the Company recorded the assets and liabilities at fair market value
as of December 31, 2017, which resulted in an impairment loss of $90 million to record BETM's goodwill at fair market value.
During the fourth quarter of 2017, NRG sold its interests in certain SPP projects to NRG Yield. The goodwill recorded
during the SPP acquisition was related primarily to its development pipeline, which was not sold to NRG Yield. As the Company
does not expect to separately develop these projects and accordingly, has no cash flow stream associated with the goodwill, an
impairment loss of $12 million was recorded to reduce the value to zero as of December 31, 2017.
Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors.
As a result, there can be no assurance that the estimates and assumptions made for purposes of the annual goodwill impairment
test will prove to be accurate predictions of the future.
Contingencies
NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable
and the amount of the loss, or range of loss, can be reasonably estimated. Gain contingencies are not recorded until management
determines it is certain that the future event will become or does become a reality. Such determinations are subject to interpretations
of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. NRG describes
in detail its contingencies in Item 15 — Note 22, Commitments and Contingencies, to the consolidated financial statements.
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Item 7A — Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
NRG is exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that
may result from market changes associated with the Company's merchant power generation or with an existing or forecasted
financial or commodity transaction. The types of market risks the Company is exposed to are commodity price risk, interest rate
risk, liquidity risk, credit risk and currency exchange risk. In order to manage these risks, the Company uses various fixed-price
forward purchase and sales contracts, futures and option contracts traded on NYMEX, and swaps and options traded in the over-
the-counter financial markets to:
• Manage and hedge fixed-price purchase and sales commitments;
• Manage and hedge exposure to variable rate debt obligations;
• Reduce exposure to the volatility of cash market prices, and
• Hedge fuel requirements for the Company's generating facilities.
Commodity Price Risk
Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities, and correlations between
various commodities, such as natural gas, electricity, coal, oil, and emissions credits. NRG manages the commodity price risk of
the Company's merchant generation operations and load serving obligations by entering into various derivative or non-derivative
instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricity and fuel. These
instruments include forwards, futures, swaps, and option contracts traded on various exchanges, such as NYMEX and ICE, as
well as over-the-counter markets. The portion of forecasted transactions hedged may vary based upon management's assessment
of market, weather, operation and other factors.
While some of the contracts the Company uses to manage risk represent commodities or instruments for which prices are
available from external sources, other commodities and certain contracts are not actively traded and are valued using other pricing
sources and modeling techniques to determine expected future market prices, contract quantities, or both. NRG uses the Company's
best estimates to determine the fair value of those derivative contracts. However, it is likely that future market prices could vary
from those used in recording mark-to-market derivative instrument valuation and such variations could be material.
NRG measures the risk of the Company's portfolio using several analytical methods, including sensitivity tests, scenario
tests, stress tests, position reports, and VaR. NRG uses a Monte Carlo simulation based VaR model to estimate the potential loss
in the fair value of the Company's energy assets and liabilities, which includes generation assets, load obligations, and bilateral
physical and financial transactions. The key assumptions for the Company's VaR model include: (i) lognormal distribution of
prices; (ii) one-day holding period; (iii) 95% confidence interval; (iv) rolling 36-month forward looking period; and (v) market
implied volatilities and historical price correlations.
As of December 31, 2017, the VaR for NRG's commodity portfolio, including generation assets, load obligations and bilateral
physical and financial transactions calculated using the VaR model was $46 million.
The following table summarizes average, maximum and minimum VaR for NRG for the years ended December 31, 2017
and 2016:
(In millions)
VaR as of December 31,
For the year ended December 31,
Average
Maximum
Minimum
$
$
2017
2016
$
$
46
51
66
40
41
53
72
32
Due to the inherent limitations of statistical measures such as VaR, the evolving nature of the competitive markets for
electricity and related derivatives, and the seasonality of changes in market prices, the VaR calculation may not capture the full
extent of commodity price exposure. As a result, actual changes in the fair value of mark-to-market energy assets and liabilities
could differ from the calculated VaR, and such changes could have a material impact on the Company's financial results.
In order to provide additional information, the Company also uses VaR to estimate the potential loss of derivative financial
instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered
into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the
diversified VaR model for the entire term of these instruments entered into for both asset management and trading was $30 million
as of December 31, 2017, primarily driven by asset-backed transactions.
NRG is exposed to fluctuations in interest rates through the Company's issuance of fixed rate and variable rate debt. Exposures
to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars
and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations
when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG's risk
management policies allow the Company to reduce interest rate exposure from variable rate debt obligations.
In addition to those discussed above, the Company's project subsidiaries enter into interest rate swaps, intended to hedge
the risks associated with interest rates on non-recourse project level debt. See Item 15 — Note 12, Debt and Capital Leases, to
the Consolidated Financial Statements, for more information about interest rate swaps of the Company's project subsidiaries.
If all of the above swaps had been discontinued on December 31, 2017, the Company would have owed the counterparties
$11 million. Based on the investment grade rating of the counterparties, NRG believes its exposure to credit risk due to
nonperformance by counterparties to its hedge contracts to be insignificant.
NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements
in market interest rates. As of December 31, 2017, a 1% change in interest rates would result in a $14.2 million change in interest
expense on a rolling twelve month basis.
As of December 31, 2017, the Company's debt fair value was $16.9 billion and carrying value was $16.6 billion. NRG
estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt by $989
million.
Liquidity Risk
Liquidity risk arises from the general funding needs of the Company's activities and in the management of the Company's
assets and liabilities. The Company is currently exposed to additional collateral posting if natural gas prices decline primarily due
to the long natural gas equivalent position at various exchanges used to hedge NRG's retail supply load obligations.
Based on a sensitivity analysis for power and gas positions under marginable contracts, a $0.50 per MMBtu change in natural
gas prices across the term of the marginable contracts would cause a change in margin collateral posted of approximately $120
million as of December 31, 2017, and a 1.00 MMBtu/MWh change in heat rates for heat rate positions would result in a change
in margin collateral posted of approximately $64 million as of December 31, 2017. This analysis uses simplified assumptions and
is calculated based on portfolio composition and margin-related contract provisions as of December 31, 2017.
Counterparty Credit Risk
Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms
of their contractual obligations. The Company monitors and manages credit risk through credit policies that include: (i) an
established credit approval process; (ii) a daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures
such as margin, collateral, prepayment arrangements, or volumetric limits; (iv) the use of payment netting agreements; and (v) the
use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with
a single counterparty. Risks surrounding counterparty performance and credit could ultimately impact the amount and timing of
expected cash flows. The Company seeks to mitigate counterparty risk by having a diversified portfolio of counterparties. The
Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash
margin is collected and held at the Company to cover the credit risk of the counterparty until positions settle.
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As of December 31, 2017, aggregate counterparty credit exposure to a significant portion of the Company's counterparties
totaled $220 million, of which the Company held collateral (cash and letters of credit) against those positions of $30 million
resulting in a net exposure of $196 million. Approximately 73% of the Company's exposure before collateral is expected to roll
off by the end of 2019. The following table highlights the net counterparty credit exposure by industry sector and by counterparty
credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where
netting is permitted under the enabling agreement and includes all cash flow, mark-to-market, NPNS, and non-derivative
transactions. As of December 31, 2017, the aggregate credit exposure is shown net of collateral held, and includes amounts net
of receivables or payables.
Category
Financial institutions
Utilities, energy merchants, marketers and other
Total
Category
Investment grade
Non-Investment grade/Non-Rated
Total
Net Exposure (a) (b)
(% of Total)
14%
86
100%
Net Exposure (a) (b)
(% of Total)
69%
31
100%
(a) Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.
(b) The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long
term contracts.
The Company has credit exposure to certain wholesale counterparties, each of which represent more than 10% of the total
net exposure discussed above and the aggregate credit exposure to such counterparties was $37 million as of December 31, 2017.
Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality,
diversification and term of the exposure in the portfolio, the Company does not anticipate a material impact on its financial position
or results of operations from nonperformance by any counterparty.
RTOs and ISOs
The Company participates in the organized markets of CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM, known as RTOs
or ISOs. Trading in these markets is approved by FERC, or in the case of ERCOT, approved by the PUCT and include credit
policies that, under certain circumstances, require that losses arising from the default of one member on spot market transactions
be shared by the remaining participants. As a result, the counterparty credit risk to these markets is limited to NRG’s applicable
share of the overall market and are excluded from the above exposures.
Long Term Contracts
Counterparty credit exposure described above excludes credit risk exposure under certain long term contracts, including
California tolling agreements, Gulf Coast load obligations, and wind and solar PPAs. As external sources or observable market
quotes are not available to estimate such exposure, the Company values these contracts based on various techniques including but
not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with
similar characteristics. Based on these valuation techniques, as of December 31, 2017, aggregate credit risk exposure managed
by NRG to these counterparties was approximately $4.1 billion, of which $2.6 billion related to assets of NRG Yield, Inc., for the
next five years. This amount excludes potential credit exposures for projects with long term PPAs that have not reached commercial
operations. The majority of these power contracts are with utilities or public power entities with strong credit quality and public
utility commission or other regulatory support. However, such regulated utility counterparties can be impacted by changes in
government regulations, which NRG is unable to predict.
Retail Customer Credit Risk
NRG is exposed to retail credit risk through its retail electricity providers, which serve C&I customers and the Mass market.
Retail credit risk results in losses when a customer fails to pay for services rendered. The losses could be incurred from nonpayment
of customer accounts receivable and any in-the-money forward value. NRG manages retail credit risk through the use of established
credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment
arrangements.
As of December 31, 2017, the Company's retail customer credit exposure to C&I and Mass customers was diversified across
many customers and various industries, as well as government entities. The Company is also subject to risk with respect to its
residential solar customers. The Company's bad debt expense resulting from credit risk was $68 million, $48 million, and $64
million for the years ending December 31, 2017, 2016, and 2015, respectively. Current economic conditions may affect the
Company's customers' ability to pay bills in a timely manner, which could increase customer delinquencies and may lead to an
increase in bad debt expense.
Credit Risk Related Contingent Features
Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if
the counterparty determines that there has been deterioration in credit quality, generally termed "adequate assurance" under the
agreements, or require the Company to post additional collateral if there were a one notch downgrade in the Company's credit
rating. The collateral required for contracts that have adequate assurance clauses that are in a net liability position as of December 31,
2017, was $25 million. The collateral required for contracts with credit rating contingent features that are in a net liability position
as of December 31, 2017, was $7 million. The Company is also a party to certain marginable agreements under which it has a
net liability position, but the counterparty has not called for the collateral due, which is approximately $4 million as of December 31,
2017.
Exchange Traded Transactions
Currency Exchange Risk
The Company enters into commodity transactions on registered exchanges, notably ICE and NYMEX. These clearinghouses
act as the counterparty and transactions are subject to extensive collateral and margining requirements. As a result, these commodity
transactions have limited counterparty credit risk.
NRG's foreign earnings and investments may be subject to foreign currency exchange risk, which NRG generally does not
hedge. As these earnings and investments are not material to NRG's consolidated results, the Company's foreign currency exposure
is limited.
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Item 8 — Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The financial statements and schedules are listed in Part IV, Item 15 of this Form 10-K.
Item 9 — Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A — Controls and Procedures
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures and Internal Control Over Financial
Reporting
Under the supervision and with the participation of NRG's management, including its principal executive officer, principal
financial officer and principal accounting officer, NRG conducted an evaluation of the effectiveness of the design and operation
of its disclosure controls and procedures, as such term is defined in Rules 13a-15(e) or 15d-15(e) of the Exchange Act. Based on
this evaluation, the Company's principal executive officer, principal financial officer and principal accounting officer concluded
that the disclosure controls and procedures were effective as of the end of the period covered by this Annual Report on Form 10-
K. Management's report on the Company's internal control over financial reporting and the report of the Company's independent
registered public accounting firm are incorporated under the caption "Management's Report on Internal Control over Financial
Reporting" and under the caption "Report of Independent Registered Public Accounting Firm" in this Annual Report on Form 10-
K for the fiscal year ended December 31, 2017.
Changes in Internal Control over Financial Reporting
There were no changes in NRG’s internal control over financial reporting (as such term is defined in Rule 13a-15(f) under
the Exchange Act) that occurred in the fourth quarter of 2017 that materially affected, or are reasonably likely to materially affect,
NRG’s internal control over financial reporting.
Inherent Limitations over Internal Controls
NRG's internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of consolidated financial statements for external purposes in accordance with GAAP. The
Company's internal control over financial reporting includes those policies and procedures that:
1. Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions
of the Company's assets;
2. Provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial
statements in accordance with GAAP, and that the Company's receipts and expenditures are being made only in accordance
with authorizations of its management and directors; and
3. Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of
the Company's assets that could have a material effect on the consolidated financial statements.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because
of its inherent limitations, including the possibility of human error and circumvention by collusion or overriding of controls.
Accordingly, even an effective internal control system may not prevent or detect material misstatements on a timely basis. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Management's Report on Internal Control over Financial Reporting
The Company's management is responsible for establishing and maintaining adequate internal control over financial
reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of the Company's
management, including its principal executive officer, principal financial officer and principal accounting officer, the Company
conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal
Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Based on the Company's evaluation under the framework in Internal Control — Integrated Framework (2013), the Company's
management concluded that its internal control over financial reporting was effective as of December 31, 2017.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2017 has been audited by
KPMG LLP, the Company's independent registered public accounting firm, as stated in its report which is included in this Annual
Report on Form 10 K.
The Board of Directors and Stockholders
NRG Energy, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited NRG Energy, Inc.’s and subsidiaries (the Company) internal control over financial reporting as of December 31,
2017, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2017, based on criteria established in Internal Control — Integrated Framework
(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the consolidated balance sheets of the Company as of December 31, 2017 and 2016, the related consolidated statements
of operations, comprehensive (loss)/income, cash flows, and stockholders’ equity for each of the years in the three-year period
ended December 31, 2017, and the related notes and financial statement schedule II (collectively, the consolidated financial
statements), and our report dated March 1, 2018 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment
of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal
Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial
reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with
respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities
and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material
respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of
internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary
in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
(signed) KPMG LLP
Philadelphia, Pennsylvania
March 1, 2018
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Item 9B — Other Information
None.
Item 10 — Directors, Executive Officers and Corporate Governance
PART III
Directors
E. Spencer Abraham has been a director of NRG since December 2012. Previously, he served as a director of GenOn Energy,
Inc. from January 2012 to December 2012. He is Chairman and Chief Executive Officer of The Abraham Group, an international
strategic consulting firm based in Washington, D.C which he founded in 2005. Prior to that, Secretary Abraham served as Secretary
of Energy under President George W. Bush from 2001 through January 2005 and was a U.S. Senator for the State of Michigan
from 1995 to 2001. Secretary Abraham serves on the boards of the following public companies: Occidental Petroleum Corporation,
PBF Energy, and Two Harbors Investment Corp., as well as chairman of the board of Uranium Energy Corp. He also serves on
the board of C3 IoT, a private company. Secretary Abraham previously served as the non-executive chairman of AREVA, Inc.,
the U.S. subsidiary of the French-owned nuclear company, and as a director of Deepwater Wind LLC, International Battery, Green
Rock Energy, ICx Technologies, PetroTiger and Sindicatum Sustainable Resources. He also previously served on the advisory
board or committees of Midas Medici (Utilipoint), Millennium Private Equity, Sunovia and Wetherly Capital.
Kirbyjon H. Caldwell has been a director of NRG since March 2009. He was a director of Reliant Energy, Inc. from August
2003 to March 2009. Since 1982, he has served as Senior Pastor at the 16,000-member Windsor Village United Methodist Church
in Houston, Texas. Pastor Caldwell was also a director of United Continental Holdings, Inc. (formerly Continental Airlines, Inc.)
from 1999 to September 2011. Pastor Caldwell is also on the Board of Trustees of Baylor College of Medicine.
Lawrence S. Coben has served as Chairman of the Board of NRG since 2017 and has been a director of NRG since December
2003. He is currently Chairman and Chief Executive Officer of Tremisis Energy Corporation LLC. Dr. Coben was Chairman and
Chief Executive Officer of Tremisis Energy Acquisition Corporation II, a publicly held company, from July 2007 through March
2009 and of Tremisis Energy Acquisition Corporation from February 2004 to May 2006. From January 2001 to January 2004, he
was a Senior Principal of Sunrise Capital Partners L.P., a private equity firm. From 1997 to January 2001, Dr. Coben was an
independent consultant. From 1994 to 1996, Dr. Coben was Chief Executive Officer of Bolivian Power Company. Dr. Coben
serves on the board of Freshpet, Inc. and served on the advisory board of Morgan Stanley Infrastructure II, L.P. from September
2014 through December 2016. Dr. Coben is also Executive Director of the Sustainable Preservation Initiative and a Consulting
Scholar at the University of Pennsylvania Museum of Archaeology and Anthropology.
Terry G. Dallas has been a director of NRG since December 2012. Previously, he served as a director of GenOn Energy, Inc.
from December 2010 to December 2012. Mr. Dallas served as a director of Mirant Corporation from 2006 until December 2010.
Mr. Dallas was also the former Executive Vice President and Chief Financial Officer of Unocal Corporation, an oil and gas
exploration and production company prior to its merger with Chevron Corporation, from 2000 to 2005. Prior to that, Mr. Dallas
held various executive finance positions in his 21-year career with Atlantic Richfield Corporation, an oil and gas company with
major operations in the United States, Latin America, Asia, Europe and the Middle East.
Mauricio Gutierrez has served as President and Chief Executive Officer of NRG since December 2015 and as a director
of NRG since January 2016. Prior to December 2015, Mr. Gutierrez was the Executive Vice President and Chief Operating Officer
of NRG from July 2010 to December 2015. Mr. Gutierrez also served as the Interim President and Chief Executive Officer of
NRG Yield, Inc. from December 2015 to May 2016 and Executive Vice President and Chief Operating Officer of NRG Yield, Inc.
from December 2012 to December 2015. Mr. Gutierrez has also served on the board of NRG Yield, Inc. since its formation in
December 2012. Mr. Gutierrez has been with NRG since August 2004 and served in multiple executive positions within NRG
including Executive Vice President - Commercial Operations from January 2009 to July 2010 and Senior Vice President -
Commercial Operations from March 2008 to January 2009. Prior to joining NRG in August 2004, Mr. Gutierrez held various
commercial positions within Dynegy, Inc.
William E. Hantke has been a director of NRG since March 2006. Mr. Hantke served as Executive Vice President and Chief
Financial Officer of Premcor, Inc., a refining company, from February 2002 until December 2005. Mr. Hantke was Corporate Vice
President of Development of Tosco Corporation, a refining and marketing company, from September 1999 until September 2001,
and he also served as Corporate Controller from December 1993 until September 1999. Prior to that position, he was employed
by Coopers & Lybrand as Senior Manager, Mergers and Acquisitions from 1989 until 1990. He also held various positions from
1975 until 1988 with AMAX, Inc., including Corporate Vice President, Operations Analysis and Senior Vice President, Finance
and Administration, Metals and Mining. He was employed by Arthur Young from 1970 to 1975 as Staff/Senior Accountant. Mr.
Hantke was Non-Executive Chairman of Process Energy Solutions, a private alternative energy company until March 31, 2008
and served as director and Vice-Chairman of NTR Acquisition Co., an oil refining start-up, until January 2009. Mr. Hantke has
served on the board of PBF Energy Inc. since February 2016.
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Paul W. Hobby has been a director of NRG since March 2006. Mr. Hobby is the Managing Partner of Genesis Park, L.P., a
Houston-based private equity business specializing in technology and communications investments which he founded in 1999.
Mr. Hobby routinely provides management and governance services to Genesis Park portfolio companies, and is currently serving
as Chairman of Texas Monthly. He previously served as the Chief Executive Officer of Alpheus Communications, Inc., a Texas
wholesale telecommunications provider from 2004 to 2011, and as Former Chairman of CapRock Services Corp., the largest
provider of satellite services to the global energy business from 2002 to 2006. From November 1992 until January 2001, he served
as Chairman and Chief Executive Officer of Hobby Media Services and was Chairman of Columbine JDS Systems, Inc. from
1995 until 1997. Mr. Hobby is former Chairman of the Houston Branch of the Federal Reserve Bank of Dallas and the Greater
Houston Partnership and is former Chairman of the Texas Ethics Commission. He was an Assistant U.S. Attorney for the Southern
District of Texas from 1989 to 1992, Chief of Staff to the Lieutenant Governor of Texas, Bob Bullock and an Associate at Fulbright &
Jaworski from 1986 to 1989.
Anne C. Schaumburg has been a director of NRG since April 2005. From 1984 until her retirement in January 2002, she
was Managing Director of Credit Suisse First Boston and a Senior Banker in the Global Energy Group. From 1979 to 1984, she
was in the Utilities Group at Dean Witter Financial Services Group, where she last served as Managing Director. From 1971 to
1978, she was at The First Boston Corporation in the Public Utilities Group. Ms. Schaumburg is also a director of Brookfield
Infrastructure Partners L.P.
Evan J. Silverstein has been a director of NRG since December 2012. Previously, he served as a director of GenOn from
August 2006 to December 2012. He served as General Partner and Portfolio Manager of SILCAP LLC, a market-neutral hedge
fund that principally invests in utilities and energy companies, from January 1993 until his retirement in December 2005. Previously,
he served as portfolio manager specializing in utilities and energy companies and as senior equity utility analyst. Mr. Silverstein
has given numerous speeches and has testified before Congress on a variety of energy-related issues. He is an audit committee
financial expert.
Barry T. Smitherman has been a director of NRG since February 2017. Mr. Smitherman is currently an energy industry
consultant and senior advisor, as well as a licensed attorney in Texas and an adjunct professor of Energy Law at The University
of Texas School of Law. From April 2015 to January 2017, Mr. Smitherman was a partner with the law firm Vinson & Elkins LLP.
Mr. Smitherman served on the Railroad Commission of Texas (RRC) from July 2011 through January 2015 where he acted as
chairman from February 2012 to August 2014. From April 2004 through July 2011, Mr. Smitherman served on the Public Utility
Commission of Texas where he acted as chairman from November 2007 through July 2011.
Thomas H. Weidemeyer has been a director of NRG since December 2003. Until his retirement in December 2003, Mr.
Weidemeyer served as Director, Senior Vice President and Chief Operating Officer of United Parcel Service, Inc., the world's
largest transportation company and President of UPS Airlines. Mr. Weidemeyer became Manager of the Americas International
Operation in 1989, and in that capacity directed the development of the UPS delivery network throughout Central and South
America. In 1990, Mr. Weidemeyer became Vice President and Airline Manager of UPS Airlines and, in 1994, was elected its
President and Chief Operating Officer. Mr. Weidemeyer became Senior Vice President and a member of the Management Committee
of United Parcel Service, Inc. that same year, and he became Chief Operating Officer of United Parcel Service, Inc. in January
2001. Mr. Weidemeyer also serves as a director of The Goodyear Tire & Rubber Co., Waste Management, Inc. and Amsted Industries
Incorporated.
C. John Wilder has been a director of NRG since February 2017. Mr. Wilder has served as the Executive Chairman and a
member of Investment Committees of three investment vehicles: (i) Bluescape Resources Company; (ii) Parallel Resource Partners;
and (iii) Bluescape Energy Partners since 2007. Wilder has served as Executive Chairman and director of Exco Resources, Inc.
from September 2015 to November 2017. Mr. Wilder is on the advisory boards of the McCombs School of Business at the University
of Texas at Austin and the A.B. Freeman School of Business at Tulane University. Mr. Wilder is a Trustee of Texas Health Resources
and is a past member of the National Petroleum Council, a Secretary of Energy Appointment.
Walter R. Young has been a director of NRG since December 2003. From May 1990 to June 2003, Mr. Young was Chairman,
Chief Executive Officer and President of Champion Enterprises, Inc., an assembler and manufacturer of manufactured homes.
Mr. Young has held senior management positions with The Henley Group, The Budd Company and BFGoodrich.
Executive Officers
Mauricio Gutierrez has served as President and Chief Executive Officer of NRG since December 2015 and as a director of
NRG since January 2016. For additional biographical information for Mr. Gutierrez, see above under "Directors."
Kirkland Andrews has served as Executive Vice President and Chief Financial Officer of NRG Energy since September 2011.
Mr. Andrews is a director of NRG Yield, Inc. and also served as Executive Vice President, Chief Financial Officer of NRG Yield,
Inc. from December 2012 to November 2016. Prior to joining NRG, he served as Managing Director and Co-Head Investment
Banking, Power and Utilities - Americas at Deutsche Bank Securities from June 2009 to September 2011. Prior to this, he served
in several capacities at Citigroup Global Markets Inc., including Managing Director, Group Head, North American Power from
November 2007 to June 2009, and Head of Power M&A, Mergers and Acquisitions from July 2005 to November 2007. In his
banking career, Mr. Andrews led multiple large and innovative strategic, debt, equity and commodities transactions.
David Callen has served as Senior Vice President and Chief Accounting Officer since February 2016 and Vice President and
Chief Accounting Officer from March 2015 to February 2016. In this capacity, Mr. Callen is responsible for directing NRG's
financial accounting and reporting activities. Mr. Callen also has served as Vice President and Chief Accounting Officer of NRG
Yield, Inc. since March 2015. Prior to this, Mr. Callen served as the Company's Vice President, Financial Planning & Analysis
from November 2010 to March 2015. He previously served as Director, Finance from October 2007 through October 2010, Director,
Financial Reporting from February 2006 through October 2007, and Manager, Accounting Research from September 2004 through
February 2006. Prior to NRG, Mr. Callen was an auditor for KPMG LLP in both New York City and Tel Aviv Israel from October
1996 through April 2001.
John Chillemi has served as Executive Vice President, National Business Development of NRG since December 2015. In
this role, Mr. Chillemi is responsible for all wholesale generation development activities for NRG across the nation. Prior to
December 2015, Mr. Chillemi was Senior Vice President and Regional President, West since the acquisition of GenOn in December
2012. Mr. Chillemi served as the Regional President in California and the West for GenOn from December 2010 to December
2012, and as President and Vice President of the West at Mirant Corporation from 2007 to December 2010. Mr. Chillemi has also
served as a director of NRG Yield, Inc. since May 2016. Mr. Chillemi has 30 years of power industry experience, beginning with
Georgia Power in 1986.
David R. Hill has served as Executive Vice President and General Counsel since September 2012. Mr. Hill also has served
as the Executive Vice President and General Counsel of NRG Yield, Inc. since December 2012. Prior to joining NRG, Mr. Hill
was a partner and co-head of Sidley Austin LLP's global energy practice group from February 2009 to August 2012. Prior to this,
Mr. Hill served as General Counsel of the U.S. Department of Energy from August 2005 to January 2009 and, for the three years
prior to that, as Deputy General Counsel for Energy Policy of the U.S. Department of Energy. Before his federal government
service, Mr. Hill was a partner in major law firms in Washington, D.C. and Kansas City, Missouri, and handled a variety of
regulatory, litigation and corporate matters.
Elizabeth Killinger has served as Executive Vice President and President, NRG Retail and Reliant of NRG since February
2016. Ms. Killinger was Senior Vice President and President, NRG Retail from June 2015 to February 2016 and Senior Vice
President and President, NRG Texas Retail from January 2013 to June 2015. Ms. Killinger has also served as President of Reliant,
a subsidiary of NRG, since October 2012. Prior to that, Ms. Killinger was Senior Vice President of Retail Operations and Reliant
Residential from January 2011 to October 2012. Ms. Killinger has been with the Company and its predecessors since 2002 and
has held various operational and business leadership positions within the retail organization. Prior to joining the Company, Ms.
Killinger spent a decade providing strategy, management and systems consulting to energy, oilfield services and retail distribution
companies across the U.S. and in Europe.
Christopher Moser has served as Executive Vice President, Operations of NRG since January 2018. Mr. Moser previously
served as Senior Vice President, Operations of NRG, with responsibility for Plant Operations, Commercial Operations, Business
Operations and Engineering and Construction, beginning in March 2016. From June 2010 to March 2016, Mr. Moser served as
Senior Vice President, Commercial Operations. In this capacity, he was responsible for the optimization of the Company's wholesale
generation fleet.
Code of Ethics
NRG has adopted a code of ethics entitled "NRG Code of Conduct" that applies to directors, officers and employees, including
the chief executive officer and senior financial officers of NRG. It may be accessed through the "Governance" section of the
Company's website at www.nrg.com. NRG also elects to disclose the information required by Form 8-K, Item 5.05, "Amendments
to the Registrant's Code of Ethics, or Waiver of a Provision of the Code of Ethics," through the Company's website, and such
information will remain available on this website for at least a 12-month period. A copy of the "NRG Energy, Inc. Code of Conduct"
is available in print to any stockholder who requests it.
120
121
Other information required by this Item will be incorporated by reference to the similarly named section of NRG's Definitive
Item 14 — Principal Accounting Fees and Services
Information required by this Item will be incorporated by reference to the similarly named section of NRG's Definitive
Proxy Statement for its 2018 Annual Meeting of Stockholders.
Proxy Statement for its 2018 Annual Meeting of Stockholders.
Item 11 — Executive Compensation
Information required by this Item will be incorporated by reference to the similarly named section of NRG's Definitive
Proxy Statement for its 2018 Annual Meeting of Stockholders.
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Securities Authorized for Issuance under Equity Compensation Plans
Plan Category
Equity compensation plans approved by security
holders
Equity compensation plans not approved by
security holders
Total
(a)
Number of Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants and Rights
(b)
Weighted-Average
Exercise
Price of Outstanding
Options, Warrants and
Rights
(c)
Number of Securities
Remaining Available
for Future Issuance
Under Equity
Compensation
Plans (Excluding
Securities Reflected
in Column (a))
6,211,050 (1) $
1,369,880 (2)
7,580,930
$
21.49
25.21
23.21
11,831,645
— (4)
11,831,645 (3)
(1) Consists of shares issuable under the NRG LTIP and the ESPP. The NRG LTIP became effective upon the Company's emergence from bankruptcy. On
April 27, 2017, the NRG LTIP was amended and restated to increase the number of shares available for issuance to 25,000,000. The ESPP, as amended and
restated, was approved by the Company's stockholders on April 27, 2017, and became effective April 28, 2017. As of December 31, 2017, there were
3,107,050 shares reserved from the Company's treasury shares for the ESPP.
(2) Consists of shares issuable under the NRG GenOn LTIP. On December 14, 2012, in connection with the Merger, NRG assumed the GenOn Energy, Inc.
2010 Omnibus Incentive Plan and changed the name to the NRG 2010 Stock Plan for GenOn Employees, or the NRG GenOn LTIP. While the GenOn
Energy, Inc. 2010 Omnibus Incentive Plan was previously approved by stockholders of RRI Energy, Inc. before it became GenOn, the plan is listed as “not
approved” because the NRG GenOn LTIP was not subject to separate line item approval by NRG's stockholders when the Merger (which included the
assumption of this plan) was approved. As part of the Merger, NRG also assumed the GenOn Energy, Inc. 2002 Long-Term Incentive Plan, the GenOn
Energy, Inc. 2002 Stock Plan, and the Mirant Corporation 2005 Omnibus Incentive Compensation Plan. NRG has no intention of making any grants or
awards of its own equity securities under these plans. The number of securities to be issued upon the exercise of outstanding awards under these plans is
227,531 at a weighted-average exercise price of $36.07. See Item 15 — Note 20, Stock-Based Compensation, to Consolidated Financial Statements for a
discussion of the NRG GenOn LTIP.
(3) Consists of 8,724,595 shares of common stock under NRG's LTIP and 3,107,050 shares of treasury stock reserved for issuance under the ESPP. In the first
quarter of 2018, 175,862 shares were issued to employees' accounts from the treasury stock reserve for the ESPP. Beginning January 2018, NRG suspended
the ESPP.
(4) Upon adoption of the NRG Amended and Restated LTIP effective April 27, 2017, no securities remain available for future issuance under the NRG GenOn
LTIP. See Note 20, Stock-Based Compensation, for additional information.
Both the NRG LTIP and the NRG GenOn LTIP provide for grants of stock options, restricted stock, market stock units,
performance stock units, deferred stock units and dividend equivalent rights. NRG's directors, officers and employees, as well as
other individuals performing services for, or to whom an offer of employment has been extended by the Company, are eligible to
receive grants under the NRG LTIP and the NRG GenOn LTIP. However, participants eligible for the NRG LTIP at the time of
the Merger are not eligible to receive grants under the NRG GenOn LTIP. The purpose of the NRG LTIP and the NRG GenOn
LTIP is to promote the Company's long-term growth and profitability by providing these individuals with incentives to maximize
stockholder value and otherwise contribute to the Company's success and to enable the Company to attract, retain and reward the
best available persons for positions of responsibility. The Compensation Committee of the Board of Directors administers the
NRG LTIP and the NRG GenOn LTIP.
Other information required by this Item will be incorporated by reference to the similarly named section of NRG's Definitive
Proxy Statement for its 2018 Annual Meeting of Stockholders.
Item 13 — Certain Relationships and Related Transactions, and Director Independence
Information required by this Item will be incorporated by reference to the similarly named section of NRG's Definitive
Proxy Statement for its 2018 Annual Meeting of Stockholders.
122
123
PART IV
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Item 15 — Exhibits, Financial Statement Schedules
(a)(1) Financial Statements
The following consolidated financial statements of NRG Energy, Inc. and related notes thereto, together with the reports
thereon of KPMG LLP, are included herein:
Consolidated Statements of Operations — Years ended December 31, 2017, 2016, and 2015
Consolidated Statements of Comprehensive (Loss)/Income — Years ended December 31, 2017, 2016, and 2015
Consolidated Balance Sheets — As of December 31, 2017 and 2016
Consolidated Statements of Cash Flows — Years ended December 31, 2017, 2016, and 2015
Consolidated Statement of Stockholders' Equity — Years ended December 31, 2017, 2016, and 2015
Notes to Consolidated Financial Statements
(a)(2) Financial Statement Schedule
The following Consolidated Financial Statement Schedule of NRG Energy, Inc. is filed as part of Item 15 of this report
and should be read in conjunction with the Consolidated Financial Statements.
Schedule II — Valuation and Qualifying Accounts
All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange
Commission are not required under the related instructions or are inapplicable, and therefore, have been omitted.
(a)(3) Exhibits: See Exhibit Index submitted as a separate section of this report.
(b) Exhibits
See Exhibit Index submitted as a separate section of this report.
(c) Not applicable
The Board of Directors and Stockholders
NRG Energy, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of NRG Energy, Inc. and subsidiaries (the Company) as of
December 31, 2017 and 2016, the related consolidated statements of operations, comprehensive (loss)/income, cash flows, and
stockholders’ equity for each of the years in the three year period ended December 31, 2017, and the related notes and financial
statement schedule II (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements
present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results
of its operations and its cash flows for each of the years in the three year period ended December 31, 2017, in conformity with
U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Company’s internal control over financial reporting as of December 31, 2017, based on criteria established in
Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission, and our report dated March 1, 2018 expressed an unqualified opinion on the effectiveness of the Company’s internal
control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB
and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether
due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated
financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included
examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits
also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the
overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
(signed) KPMG LLP
We have served as the Company's auditor since 2004.
Philadelphia, Pennsylvania
March 1, 2018
124
125
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME
Net Loss
Other Comprehensive Income, net of tax
Unrealized gain/(loss) on derivatives, net of income tax expense of $1, $1, and
$19
Foreign currency translation adjustments, net of income tax benefit of $(2), $0,
and $0
Available-for-sale securities, net of income tax expense/(benefit) of $10, $0, and
$(3)
Defined benefit plan, net of income tax (benefit)/expense of $(21), $0 and $69
Other comprehensive income
Comprehensive Loss
Less: Comprehensive loss attributable to noncontrolling interests and redeemable
noncontrolling interests
Comprehensive Loss Attributable to NRG Energy, Inc.
Dividends for preferred shares
Gain on redemption of preferred shares
For the Year Ended December 31,
2017
2016
2015
(In millions)
$
(2,337) $
(891) $
(6,436)
13
12
(8)
46
63
(2,274)
(179)
(2,095)
—
—
35
(1)
1
3
38
(853)
(117)
(736)
5
(78)
(15)
(11)
17
10
1
(6,435)
(73)
(6,362)
20
—
Comprehensive Loss Available for Common Stockholders
$
(2,095) $
(663) $
(6,382)
See notes to Consolidated Financial Statements.
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per share amounts)
Operating Revenues
Total operating revenues
Operating Costs and Expenses
Cost of operations
Depreciation and amortization
Impairment losses
Selling, general and administrative
Reorganization costs
Development costs
Total operating costs and expenses
Other income - affiliate
Gain/(loss) on sale of assets
Gain on postretirement benefits curtailment
Operating (Loss)/Income
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates
Impairment losses on investments
Other income, net
Loss on sale of equity method investment
Net (loss)/gain on debt extinguishment
Interest expense
Total other expense
Loss from Continuing Operations Before Income Taxes
Income tax expense
Net Loss from Continuing Operations
(Loss)/income from discontinued operations, net of income tax
Net Loss
Less: Net loss attributable to noncontrolling interests and redeemable
noncontrolling interests
Net Loss Attributable to NRG Energy, Inc.
Dividends for preferred shares
Gain on redemption of preferred shares
Loss Available for Common Stockholders
Loss Per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic and diluted
Loss from continuing operations per weighted average common share — basic and
diluted
(Loss)/Income from discontinued operations per weighted average common share —
basic and diluted
Net Loss per Weighted Average Common Share — Basic and Diluted
Dividends Per Common Share
$
$
$
$
$
See notes to Consolidated Financial Statements.
For the Year Ended December 31,
2017
2016
2015
$
10,629
$
10,512
$
12,328
7,536
1,056
1,709
907
44
67
11,319
87
16
—
(587)
31
(79)
38
—
(53)
(890)
(953)
(1,540)
8
(1,548)
(789)
(2,337)
7,301
1,172
702
1,095
—
89
10,359
193
(80)
—
266
27
(268)
34
—
(142)
(895)
(1,244)
(978)
5
(983)
92
(891)
(184)
(2,153)
—
—
(2,153) $
(117)
(774)
5
(78)
(701) $
9,000
1,351
4,860
1,228
—
154
16,593
193
—
21
(4,051)
36
(56)
26
(14)
10
(937)
(935)
(4,986)
1,345
(6,331)
(105)
(6,436)
(54)
(6,382)
20
—
(6,402)
317
316
329
(4.30) $
(2.51) $
(19.14)
(2.49) $
(6.79) $
$
0.12
0.29
$
(2.22) $
$
0.24
(0.32)
(19.46)
0.58
126
127
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Current Assets
ASSETS
Cash and cash equivalents
Funds deposited by counterparties
Restricted cash
Accounts receivable — trade
Inventory
Derivative instruments
Cash collateral posted in support of energy risk management activities
Accounts receivable — affiliate
Current assets held-for-sale
Prepayments and other current assets
Current assets - discontinued operations
Total current assets
Property, plant and equipment, net
Other Assets
Equity investments in affiliates
Notes receivable, less current portion
Goodwill
Intangible assets, net
Nuclear decommissioning trust fund
Derivative instruments
Deferred income taxes
Non-current assets held-for-sale
Other non-current assets
Non-current assets - discontinued operations
Total other assets
Total Assets
See notes to Consolidated Financial Statements.
As of December 31,
2017
2016
(In millions)
$
$
991
37
508
1,079
532
626
171
95
115
261
—
4,415
13,908
1,038
2
539
1,746
692
172
134
43
629
—
4,995
23,318
$
$
938
2
446
1,058
721
1,067
150
—
9
404
1,919
6,714
15,369
1,120
16
662
1,973
610
181
225
10
841
2,961
8,599
30,682
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Continued)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and capital leases
Accounts payable
Accounts payable - affiliate
Derivative instruments
Cash collateral received in support of energy risk management activities
Accrued interest expense
Current liabilities - held for sale
Other accrued expenses and other current liabilities
Other accrued expenses and other current liabilities - affiliate
Current liabilities - discontinued operations
Total current liabilities
Other Liabilities
Long-term debt and capital leases
Nuclear decommissioning reserve
Nuclear decommissioning trust liability
Postretirement and other benefit obligations
Deferred income taxes
Derivative instruments
Out-of-market contracts, net
Non-current liabilities held-for-sale
Other non-current liabilities
Non-current liabilities - discontinued operations
Total non-current liabilities
Total Liabilities
Redeemable noncontrolling interest in subsidiaries
Commitments and Contingencies
Stockholders' Equity
Common stock; $0.01 par value; 500,000,000 shares authorized; 418,323,134 and
417,583,825 shares issued; and 316,743,089 and 315,443,011 shares outstanding at
December 31, 2017 and 2016
Additional paid-in capital
Accumulated deficit
Treasury stock, at cost; 101,580,045 and 102,140,814 shares at December 31, 2017
and 2016
Accumulated other comprehensive loss
Noncontrolling interest
Total Stockholders' Equity
Total Liabilities and Stockholders' Equity
See notes to Consolidated Financial Statements.
As of December 31,
2017
2016
(In millions, except share data)
$
$
$
688
881
33
555
37
156
72
734
161
—
3,317
15,716
269
415
458
21
197
207
8
664
—
17,955
21,272
78
4
8,376
(6,268)
(2,386)
(72)
2,314
1,968
23,318
$
516
782
31
1,092
81
180
—
810
—
1,210
4,702
15,957
287
339
510
20
284
230
11
666
3,184
21,488
26,190
46
4
8,358
(3,787)
(2,399)
(135)
2,405
4,446
30,682
128
129
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Year Ended December 31,
2016
2017
2015
Cash Flows from Operating Activities
Net loss
(Loss)/income from discontinued operations, net of income tax
Loss from continuing operations
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Equity in earnings and distribution of unconsolidated affiliates
Depreciation and amortization
Provision for bad debts
Amortization of nuclear fuel
Amortization of financing costs and debt discount/premiums
Adjustment for debt extinguishment
Amortization of intangibles and out-of-market contracts
Amortization of unearned equity compensation
Net (gain)/loss on sale of assets and equity method investments
Gain on post retirement benefits curtailment
Impairment losses
Changes in derivative instruments
Changes in deferred income taxes and liability for uncertain tax benefits
Changes in collateral deposits in support of risk management activities
Proceeds from sale of emission allowances
Changes in nuclear decommissioning trust liability
Cash provided/(used) by changes in other working capital, net of acquisition and disposition effects:
Accounts receivable - trade
Inventory
Prepayments and other current assets
Accounts payable
Accrued expenses and other current liabilities
Other assets and liabilities
Cash provided by continuing operations
Cash (used)/provided by discontinued operations
Net Cash Provided by Operating Activities
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired
Capital expenditures
Net cash proceeds from notes receivable
Proceeds from renewable energy grants
Proceeds from/(purchases) of emission allowances, net of purchases
Investments in nuclear decommissioning trust fund securities
Proceeds from sales of nuclear decommissioning trust fund securities
Proceeds from sale of assets, net
Investments in unconsolidated affiliates
Other
Cash used by continuing operations
Cash (used)/provided by discontinued operations
Net Cash Used by Investing Activities
Cash Flows from Financing Activities
Payments of dividends to preferred and common stockholders
Net receipts from settlement of acquired derivatives that include financing elements
Payments for treasury stock
Payments for preferred shares
Payments for debt extinguishment costs
Distributions to, net of contributions from, noncontrolling interests in subsidiaries
Proceeds from sale of noncontrolling interests in subsidiaries
(Payments)/Proceeds from issuance of common stock
Proceeds from issuance of long-term debt
Payments of debt issuance and hedging costs
Payments for short and long-term debt
Receivable from affiliate
Other
Cash used by continuing operations
Cash (used)/provided by discontinued operations
Net Cash Used by Financing Activities
Effect of exchange rate changes on cash and cash equivalents
Change in Cash from discontinued operations
Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted
Cash
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period
(In millions)
(2,337)
(789)
(1,548) $
$
(891)
92
(983) $
(6,436)
(105)
(6,331)
55
1,056
68
51
60
53
108
35
(34)
—
1,788
(171)
91
(80)
25
11
(99)
143
12
77
(60)
(216)
1,425
(38)
1,387
(41)
(1,111)
17
8
66
(512)
501
87
(40)
12
(1,013)
(53)
(1,066)
(38)
2
—
—
(42)
95
—
(2)
2,270
(63)
(2,348)
(125)
(10)
(261)
(224)
(485)
(1)
(315)
150
1,386
54
1,172
48
49
55
142
167
10
70
—
972
32
(43)
398
34
41
(7)
71
(44)
(39)
(35)
43
2,207
(119)
2,088
(209)
(976)
17
36
(1)
(551)
510
73
(23)
35
(1,089)
297
(792)
(76)
6
—
(226)
(121)
(156)
—
1
5,527
(89)
(5,908)
—
(13)
(1,055)
140
(915)
1
318
64
1,322
37
1,351
64
45
47
(10)
151
39
14
(21)
4,916
235
1,326
(334)
(24)
(2)
113
(59)
(21)
(180)
(29)
(40)
1,287
62
1,349
(31)
(1,029)
18
82
41
(629)
631
27
(395)
16
(1,269)
(259)
(1,528)
(201)
14
(437)
—
—
47
600
1
1,004
(21)
(1,362)
—
(22)
(377)
(55)
(432)
10
(252)
(349)
1,671
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
Common
Stock
Additional
Paid-In
Capital
Retained
Earnings/
(Accumu-
lated
Deficit)
Accumulated
Other
Comprehensive
Income/(Loss)
Noncon-
trolling
Interest
Total
Stock-
holders'
Equity
Treasury
Stock
(In millions)
Balances at December 31, 2014
$
4
$
8,327
$
3,588
$ (1,983) $
(174) $
1,914
Net loss
Other comprehensive income/(loss)
Sale of assets to NRG Yield, Inc.
ESPP share purchases
Equity-based compensation
Purchase of treasury stock
Common stock dividends
Preferred stock dividends
Distributions to noncontrolling interests
Contributions from noncontrolling interests
Acquisition of noncontrolling interests by NRG Yield, Inc.
Impact of NRG Yield, Inc. public offering
Equity component of NRG Yield, Inc. convertible notes
(56)
(1)
26
(6,382)
(2)
(191)
(20)
7
(437)
1
(37)
(4)
83
(159)
234
74
599
23
11,676
(6,419)
(3)
27
6
24
(437)
(191)
(20)
(159)
234
74
599
23
Balances at December 31, 2015
$
4
$
8,296
$
(3,007) $ (2,413) $
(173) $
2,727
$
5,434
Net loss
Other comprehensive income
Sale of assets to NRG Yield, Inc.
ESPP share purchases
Equity-based compensation
Common stock dividends
Dividend for preferred shares
Gain on redemption of preferred shares
Distributions to noncontrolling interests
Dividends paid to NRG Yield, Inc.
Contributions from noncontrolling interests
Redemption of noncontrolling interests
59
(2)
5
(774)
(6)
1
(74)
(5)
78
(79)
(853)
38
(16)
14
(158)
(92)
30
(7)
38
43
6
6
(74)
(5)
78
(158)
(92)
30
(7)
Balances at December 31, 2016
$
4
$
8,358
$
(3,787) $ (2,399) $
(135) $
2,405
$
4,446
Net loss
Other comprehensive income
Sale of assets to NRG Yield, Inc.
ESPP share purchases
Equity-based compensation
Common stock dividends
Distributions to noncontrolling interests
Dividends paid to NRG Yield, Inc.
Contributions from noncontrolling interests
Early adoption of new accounting standards
(2,153)
(98)
(2,251)
51
(25)
(3)
29
(4)
13
(38)
17
(286)
12
20
(65)
(108)
160
51
(5)
6
29
(38)
(65)
(108)
160
(257)
Balances at December 31, 2017
$
4
$
8,376
$
(6,268) $ (2,386) $
(72) $
2,314
$
1,968
See notes to Consolidated Financial Statements.
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period
$
1,536
$
1,386
$
1,322
See notes to Consolidated Financial Statements.
130
131
NRG ENERGY, INC. AND SUBSIDIARIES
Transformation Plan
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 — Nature of Business
General
NRG Energy, Inc., or NRG or the Company, is a leading integrated power company built on the strength of a 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 30,000 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.
Generation consists of the Company’s wholesale operations, commercial operations, EPC operations, energy services and
other critical related functions. NRG has traditionally referred to this business as its wholesale power generation business. In
addition to the traditional functions from NRG’s wholesale power generation business, Generation also includes NRG’s business
solutions, which include demand response, commodity sales, energy efficiency and energy management services, and NRG’s
conventional distributed generation business, consisting of reliability, combined heat and power, thermal and district heating and
cooling and large-scale distributed generation.
Retail is a consumer facing business that includes the Company’s residential retail and C&I business. Products and services
range from retail energy, portable solar and battery products home services, and a variety of bundled products which combine
energy with protection products, energy efficiency and renewable energy solutions as well as other distributed and reliability
products.
Renewables operates the Company’s existing renewables business, including operation of the NRG Yield renewable assets.
Renewables is also one of the largest solar and wind power developers and owner-operators in the U.S., having developed,
constructed and financed a full range of solutions for utilities, schools, municipalities and commercial market segments.
GenOn Chapter 11 Cases
On June 14, 2017, or the Petition Date, GenOn, along with GenOn Americas Generation and certain of their directly and
indirectly-owned subsidiaries, or collectively the GenOn Entities, filed voluntary petitions for relief under Chapter 11, or the
Chapter 11 Cases, of the U.S. Bankruptcy Code, or the Bankruptcy Code, in the U.S. Bankruptcy Court for the Southern District
of Texas, Houston Division, or the Bankruptcy Court. GenOn Mid-Atlantic, as well as its consolidated subsidiaries, REMA and
certain other subsidiaries, did not file for relief under Chapter 11.
As a result of the bankruptcy filings and beginning on June 14, 2017, GenOn and its subsidiaries were deconsolidated from
NRG’s consolidated financial statements. NRG recorded its investment in GenOn under the cost method with an estimated fair
value of zero. NRG determined that this disposal of GenOn and its subsidiaries is a discontinued operation; and, accordingly, the
financial information for all historical periods has been recast to reflect GenOn as a discontinued operation. In connection with
the disposal, NRG recorded a loss on deconsolidation of $208 million during the quarter ended June 30, 2017. See Note 3,
Discontinued Operations, Acquisitions and Dispositions, for more information.
Prior to the GenOn Entities' filing the Chapter 11 Cases, on June 12, 2017, NRG entered into a restructuring support and
lock-up agreement, or the Restructuring Support Agreement, with the GenOn Entities and certain holders of the GenOn and GenOn
Americas Generation Senior Notes, that provides for a restructuring and recapitalization of the GenOn Entities through a prearranged
plan of reorganization. On December 12, 2017, the Bankruptcy Court entered an order confirming the plan of reorganization.
There is no assurance that the GenOn Entities' plan will be successfully implemented. The principal terms of the Restructuring
Support Agreement and further information regarding the Chapter 11 Cases are described further in Note 3, Discontinued
Operations, Acquisitions and Dispositions.
On July 12, 2017, NRG announced its Transformation Plan designed to significantly strengthen earnings and cost
competitiveness, lower risk and volatility, and create significant shareholder value. The three-part, three-year plan is comprised
of the following targets:
Operations and cost excellence — Cost savings and margin enhancement of $1,065 million recurring, which consists of
$590 million of annual cost savings, a $215 million net margin enhancement program, $50 million annual reduction in
maintenance capital expenditures, and $210 million in permanent selling, general and administrative expense reduction
associated with asset sales.
Portfolio optimization — Targeting up to $3.2 billion of asset sale net cash proceeds, including divestitures of 6 GWs of
conventional generation and businesses (excluding GenOn) and the expected monetization of 100% of its interest in NRG
Yield, Inc. and its renewables platform.
Capital structure and allocation enhancements — A prioritized capital allocation strategy that targets a reduction in
consolidated debt from approximately $19.5 billion ($18 billion net debt) to approximately $6.5 billion ($6 billion net debt).
Following the completion of the contemplated asset sales, the Company expects $5.3 billion in excess cash to be available
for allocation through 2020, after achieving its targeted 3.0x net debt / Adjusted EBITDA corporate credit ratio.
The Company expects to fully implement the Transformation Plan by the end of 2020 with significant completion by the
end of 2018. The Company expects to realize (i) $370 million of working capital improvements through 2020 and (ii) approximately
$290 million, one-time costs to achieve.
NRG Yield, Inc. Ownership
In 2013, the Company formed NRG Yield, Inc. to own and operate a portfolio of contracted generation assets and thermal
infrastructure assets that have historically been owned and/or operated by NRG and its subsidiaries. In 2013 and 2014, NRG Yield,
Inc. issued Class A common stock to its public shareholders and utilized the proceeds to acquire a controlling interest in NRG
Yield LLC, through its ownership of Class A units. At that time, the Company owned the Class B common stock of NRG Yield,
Inc. and the Class B units of NRG Yield LLC. On May 14, 2015, NRG Yield, Inc. completed a stock split in connection with
which each outstanding share of Class A common stock was split into one share of Class A common stock and one share of Class
C common stock, and each outstanding share of Class B common stock was split into one share of Class B common stock and
one share of Class D common stock. A similar split was effected at NRG Yield LLC with respect to its member units. The Company
consolidates NRG Yield, Inc. for financial reporting purposes as it maintains a controlling voting interest, and presents the public
ownership of the Class A and Class C common stock as noncontrolling interest. The Company receives distributions from NRG
Yield LLC, through its ownership of Class B and Class D units.
132
133
The following table represents the structure of NRG Yield, Inc. as of December 31, 2017:
Cash and Cash Equivalents
Cash and cash equivalents include highly liquid investments with an original maturity of three months or less at the time of
purchase.
Funds Deposited by Counterparties
Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its
counterparties. Some amounts are segregated into separate accounts that are not contractually restricted but, based on the Company's
intention, are not available for the payment of general corporate obligations. Depending on market fluctuations and the settlement
of the underlying contracts, the Company will refund this collateral to the hedge counterparties pursuant to the terms and conditions
of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be
held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance
sheet, with an offsetting liability for this cash collateral received within current liabilities. As of December 31, 2016, $79 million
of the cash collateral received was from GenOn, previously a consolidated subsidiary, and is included in cash collateral received
in current liabilities as a result of deconsolidating GenOn, with the offset included in cash and cash equivalents.
Restricted Cash
The following table provides a reconciliation of cash and cash equivalents, restricted cash and funds deposited by
counterparties reported within the consolidated balance sheet that sum to the total of the same such amounts shown in the statement
of cash flows.
Cash and cash equivalents
Funds deposited by counterparties
Restricted cash
Cash and cash equivalents, funds deposited by counterparties and restricted
cash shown in the statement of cash flows
Year Ended December 31,
2017
2016
2015
(In millions)
991
$
938
$
37
508
2
446
853
55
414
1,536
$
1,386
$
1,322
$
$
Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within
the Company's projects that are restricted in their use. Of these funds, as of December 31, 2017, approximately $51 million is
designated for current debt service payments, $65 million is designated to fund operating expenses, and $57 million is designated
to fund distributions, with the remaining $335 million restricted for reserves including debt service, performance obligations and
other reserves, as well as capital expenditures.
Trade Receivables and Allowance for Doubtful Accounts
Trade receivables are reported in the balance sheet at outstanding principal adjusted for any write-offs and the allowance
for doubtful accounts. For its retail business, the Company accrues an allowance for doubtful accounts based on estimates of
uncollectible revenues by analyzing counterparty credit ratings (for commercial and industrial customers), historical collections,
accounts receivable aging and other factors. The retail business writes-off accounts receivable balances against the allowance for
doubtful accounts when it determines a receivable is uncollectible. In addition, the Company considers a reserve for doubtful
accounts based on the credit worthiness of the customers and continually reviews and adjusts for current economic trends that
might impact the level of future credit losses. The reserve represents management's best estimate of uncollectible amounts. As of
December 31, 2017 and 2016, the allowance for doubtful accounts was $28 million and $29 million, respectively.
Inventory
Inventory is valued at the lower of weighted average cost or market, and consists principally of fuel oil, coal and raw materials
used to generate electricity or steam. The Company removes these inventories as they are used in the production of electricity or
steam. Spare parts inventory is valued at weighted average cost. The Company removes these inventories when they are used
for repairs, maintenance or capital projects. The Company expects to recover the fuel oil, coal, raw materials, and spare parts
costs in the ordinary course of business. Finished goods inventory is valued at the lower of cost or net realizable value with cost
being determined on a first-in first-out basis. The Company removes these inventories as they are sold to customers. Sales of
inventory are classified as an operating activity in the consolidated statements of cash flows.
Note 2 — Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
The Company's consolidated financial statements have been prepared in accordance with GAAP. The ASC, established by
the FASB, is the source of authoritative GAAP to be applied by nongovernmental entities. In addition, the rules and interpretative
releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants.
The consolidated financial statements include NRG's accounts and operations and those of its subsidiaries in which the
Company has a controlling interest. All significant intercompany transactions and balances have been eliminated in consolidation.
The usual condition for a controlling financial interest is ownership of a majority of the voting interests of an entity. However, a
controlling financial interest may also exist through arrangements that do not involve controlling voting interests. As such, NRG
applies the guidance of ASC 810, Consolidations, or ASC 810, to determine when an entity that is insufficiently capitalized or
not controlled through its voting interests, referred to as a VIE, should be consolidated.
Segment Reporting
The Company's businesses are segregated as follows: Generation, which includes generation, international and BETM;
Retail, which includes Mass customers, and Business Solutions, which includes C&I customers and other distributed and reliability
products; Renewables, which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and corporate activities. On
June 14, 2017, as described in Note 3, Discontinued Operations, Acquisitions and Dispositions, NRG deconsolidated GenOn for
financial reporting purposes. The financial information for all historical periods has been recast to reflect the presentation of GenOn
as discontinued operations within the corporate segment. The Company's segment structure and its allocation of corporate expenses
were updated to reflect how management makes financial decisions and allocates resources. The Company has recast data from
prior periods to reflect this change in reportable segments to conform to the current year presentation.
134
135
Property, Plant and Equipment
Property, plant and equipment are stated at cost or, in the case of business acquisitions, fair value; however, impairment
adjustments are recorded whenever events or changes in circumstances indicate that their carrying values may not be recoverable.
See Note 3, Discontinued Operations, Acquisitions and Dispositions, for more information on acquired property, plant and
equipment. NRG also classifies nuclear fuel related to the Company's 44% ownership interest in STP as part of the Company's
property, plant, and equipment. Significant additions or improvements extending asset lives are capitalized as incurred, while
repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred.
Depreciation, other than nuclear fuel, is computed using the straight-line method, while nuclear fuel is amortized based on units
of production over the estimated useful lives. Certain assets and their related accumulated depreciation amounts are adjusted for
asset retirements and disposals with the resulting gain or loss included in cost of operations in the consolidated statements of
operations.
Asset Impairments
Long-lived assets that are held and used are reviewed for impairment whenever events or changes in circumstances indicate
carrying values may not be recoverable. Such reviews are performed in accordance with ASC 360. An impairment loss is indicated
if the total future estimated undiscounted cash flows expected from an asset are less than its carrying value. An impairment charge
is measured by the difference between an asset's carrying amount and fair value with the difference recorded in operating costs
and expenses in the consolidated statements of operations. Fair values are determined by a variety of valuation methods, including
third-party appraisals, sales prices of similar assets, and present value techniques.
Investments accounted for by the equity method are reviewed for impairment in accordance with ASC 323, Investments-
Equity Method and Joint Ventures, or ASC 323, which requires that a loss in value of an investment that is an other-than-temporary
decline should be recognized. The Company identifies and measures losses in the value of equity method investments based upon
a comparison of fair value to carrying value.
For further discussion of these matters, refer to Note 10, Asset Impairments.
Development Costs and Capitalized Interest
Development costs include project development costs, which are expensed in the preliminary stages of a project and
capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions
including, among others, Board of Director approval pursuant to a formal project plan that subjects the Company to significant
future obligations that can only be discharged by the use of a Company asset. When a project is available for operations, capitalized
interest and capitalized project development costs are reclassified to property, plant and equipment and depreciated on a straight-
line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is
abandoned or management otherwise determines the costs to be unrecoverable.
Interest incurred on funds borrowed to finance capital projects is capitalized until the project under construction is ready for
its intended use. The amount of interest capitalized for the years ended December 31, 2017, 2016, and 2015, was $34 million, $30
million, and $25 million, respectively.
Debt Issuance Costs
Debt issuance costs are capitalized and amortized as interest expense on a basis which approximates the effective interest
method over the term of the related debt. Debt issuance costs are presented as a direct deduction from the carrying amount of the
related debt.
Intangible Assets
Intangible assets represent contractual rights held by the Company. The Company recognizes specifically identifiable
intangible assets including customer contracts, customer relationships, energy supply contracts, marketing partnerships, power
purchase agreements, trade names, emission allowances, and fuel contracts when specific rights and contracts are acquired. In
addition, the Company also established values for emission allowances and power contracts upon adoption of Fresh Start reporting.
These intangible assets are amortized based on expected volumes, expected delivery, expected discounted future net cash flows,
straight line or units of production basis. As of December 31, 2017 and 2016, the Company had accumulated amortization related
to its intangible assets of $1.8 billion and $1.7 billion, respectively.
Intangible assets determined to have indefinite lives are not amortized, but rather are tested for impairment at least annually
or more frequently if events or changes in circumstances indicate that such acquired intangible assets have been determined to
have finite lives and should now be amortized over their useful lives.
Emission allowances held-for-sale, which are included in other non-current assets on the Company's consolidated balance
sheet, are not amortized; they are carried at the lower of cost or fair value and reviewed for impairment in accordance with ASC
360.
Goodwill
In accordance with ASC 350, the Company recognizes goodwill for the excess cost of an acquired entity over the net value
assigned to assets acquired and liabilities assumed. NRG performs goodwill impairment tests annually, during the fourth quarter,
and when events or changes in circumstances indicate that the carrying value may not be recoverable.
The Company first assesses qualitative factors to determine whether it is more likely than not that the fair value of a reporting
unit is less than its carrying amount. The more-likely-than-not threshold is defined as having a likelihood of more than 50 percent.
If it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, there is no goodwill impairment.
In the absence of sufficient qualitative factors, the Company performs a quantitative assessment by determining the fair value
of the reporting unit and comparing the fair value to its book value. If the fair value of the reporting unit exceeds its book value,
goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, the Company recognizes an
impairment loss equal to the difference between book value and fair value.
For further discussion of goodwill and goodwill impairment losses recognized during 2017 and 2016, refer to Note 11,
Goodwill and Other Intangibles.
Income Taxes
The Company accounts for income taxes using the liability method in accordance with ASC 740, which requires that the
Company use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all
significant temporary differences.
The Company has two categories of income tax expense or benefit — current and deferred, as follows:
• Current income tax expense or benefit consists solely of current taxes payable less applicable tax credits, and
• Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding amounts
charged or credited to accumulated other comprehensive income.
The Company reports some of its revenues and expenses differently for financial statement purposes than for income tax
return purposes, resulting in temporary and permanent differences between the Company's financial statements and income tax
returns. The tax effects of such temporary differences are recorded as either deferred income tax assets or deferred income tax
liabilities in the Company's consolidated balance sheets. The Company measures its deferred income tax assets and deferred
income tax liabilities using income tax rates that are currently in effect. The Company believes it is more likely than not that the
results of future operations will generate sufficient taxable income which includes the future reversal of existing taxable temporary
differences to realize deferred tax assets, net of valuation allowances. In arriving at this conclusion to utilize projections of future
profit before tax in its estimate of future taxable income, including the potential impact of the Tax Cuts and Jobs Act legislation,
or the Tax Act, the Company considered the profit before tax generated in recent years. A valuation allowance is recorded to
reduce the Company's net deferred tax assets to an amount that is more-likely-than-not to be realized.
The Company reduces its current income tax expense in the consolidated statement of operations for any investment tax
credits, or ITCs, that are not convertible into cash grants, as well as other tax credits, in the period the tax credit is generated. ITCs
that are convertible into cash grants, as well as the deferred income tax benefit generated by the difference in the financial statement
and tax basis of the related assets, are recorded as a reduction to the carrying value of the underlying property and subsequently
amortized to earnings on a straight-line basis over the useful life of each underlying property.
The Company accounts for uncertain tax positions in accordance with ASC 740, which applies to all tax positions related
to income taxes. Under ASC 740, tax benefits are recognized when it is more-likely-than-not that a tax position will be sustained
upon examination by the authorities. The benefit recognized from a position that has surpassed the more-likely-than-not threshold
is the largest amount of benefit that is more than 50% likely to be realized upon settlement. The Company recognizes interest and
penalties accrued related to uncertain tax benefits as a component of income tax expense.
In accordance with ASC 805 and as discussed further in Note 19, Income Taxes, changes to existing net deferred tax assets
or valuation allowances or changes to uncertain tax benefits, are recorded to income tax expense.
136
137
Revenue Recognition
Cost of Energy for Retail Operations
Energy — Both physical and financial transactions are entered into to optimize the financial performance of the Company's
generating facilities. Electric energy revenue is recognized upon transmission to the customer. Physical transactions, or the sale
of generated electricity to meet supply and demand, are recorded on a gross basis in the Company's consolidated statements of
operations. Financial transactions, or the buying and selling of energy for trading purposes, are recorded net within operating
revenues in the consolidated statements of operations in accordance with ASC 815.
Capacity — Capacity revenues are recognized when contractually earned, and consist of revenues billed to a third party at
either the market or a negotiated contract price for making installed generation capacity available in order to satisfy system integrity
and reliability requirements.
Sale of Emission Allowances — The Company records its bank of emission allowances as part of intangible assets. From
time to time, management may authorize the transfer of emission allowances in excess of usage from the Company's emission
bank to intangible assets held-for-sale for trading purposes. The Company records the sale of emission allowances on a net basis
within operating revenue in the Company's consolidated statements of operations.
Contract Amortization — Assets and liabilities recognized from power sales agreements assumed at Fresh Start and through
acquisitions related to the sale of electric capacity and energy in future periods for which the fair value has been determined to be
significantly less (more) than market are amortized to revenue over the term of each underlying contract based on actual generation
and/or contracted volumes.
Retail revenues — Gross revenues for energy sales and services to retail customers are recognized upon delivery under the
accrual method. Energy sales and services that have been delivered but not billed by period end are estimated. Gross revenues
also includes energy revenues from resales of purchased power, which were $187 million, $154 million and $165 million for the
years ended December 31, 2017, 2016, and 2015, respectively. These revenues represent the sale of excess supply to third parties
in the market.
Accrued unbilled revenues are based on estimates of customer usage since the date of the last meter reading provided by the
independent system operators or electric distribution companies. Volume estimates are based on daily forecasted volumes and
estimated customer usage by class. Unbilled revenues are calculated by multiplying these volume estimates by the applicable rate
by customer class. Estimated amounts are adjusted when actual usage is known and billed. The Company recorded receivables
for unbilled revenues of $376 million, $321 million and $307 million as of December 31, 2017, 2016, and 2015, respectively, for
retail energy sales and services.
Consumer product revenues are recognized when title and risk of loss pass to the retailer, distributor, or end-customer and
when all of the following have occurred: a firm sales agreement is in place, delivery has occurred, pricing is fixed and determinable,
and collection is reasonably assured. Revenue is recognized as the net amount expected to be received after deducting estimated
amounts for product returns, discounts, and allowances based on historical return rates and reasonable judgment.
Lessor Accounting
Certain of the Company’s revenues are obtained through PPAs or other contractual agreements. Many of these agreements
are accounted for as operating leases under ASC 840 Leases.
Certain of these leases have no minimum lease payments and all of the rent is recorded as contingent rent on an actual basis
when the electricity is delivered. Judgment is required by management in determining the economic life of each generating facility,
in evaluating whether certain lease provisions constitute minimum payments or represent contingent rent and other factors in
determining whether a contract contains a lease and whether the lease is an operating lease or capital lease. Contingent rental
income recognized in the years ended December 31, 2017, 2016, and 2015 was $879 million, $912 million, and $753 million,
respectively.
Gross Receipts and Sales Taxes
In connection with its retail business, the Company records gross receipts taxes on a gross basis in revenues and cost of
operations in its consolidated statements of operations. During the years ended December 31, 2017, 2016, and 2015, the Company's
revenues and cost of operations included gross receipts taxes of $92 million, $101 million, and $110 million, respectively.
Additionally, the retail business records sales taxes collected from its taxable customers and remitted to the various governmental
entities on a net basis; thus, there is no impact on the Company's consolidated statement of operations.
The cost of energy for electricity sales and services to retail customers is included in cost of operations and is based on
estimated supply volumes for the applicable reporting period. A portion of the cost of energy ($107 million, $90 million and $85
million as of December 31, 2017, 2016, and 2015, respectively) was accrued and consisted of estimated transmission and
distribution charges not yet billed by the transmission and distribution utilities. In estimating supply volumes, the Company
considers the effects of historical customer volumes, weather factors and usage by customer class. Transmission and distribution
delivery fees are estimated using the same method used for electricity sales and services to retail customers. In addition, ISO fees
are estimated based on historical trends, estimated supply volumes and initial ERCOT ISO settlements. Volume estimates are then
multiplied by the supply rate and recorded as cost of operations in the applicable reporting period.
Derivative Financial Instruments
The Company accounts for derivative financial instruments under ASC 815, which requires the Company to record all
derivatives on the balance sheet at fair value unless they qualify for a NPNS exception. Changes in the fair value of non-hedge
derivatives are immediately recognized in earnings. Changes in the fair value of derivatives accounted for as cash flow hedges,
if elected for hedge accounting, are deferred and recorded as a component of accumulated OCI until the hedged transactions occur
and are recognized in earnings.
The Company's primary derivative instruments are power purchase or sales contracts, fuels purchase contracts, other energy
related commodities, and interest rate instruments used to mitigate variability in earnings due to fluctuations in market prices and
interest rates. On an ongoing basis, the Company assesses the effectiveness of all derivatives that are designated as hedges for
accounting purposes in order to determine that each derivative continues to be highly effective in offsetting changes in fair values
or cash flows of hedged items. Internal analyses that measure the statistical correlation between the derivative and the associated
hedged item determine the effectiveness of such a contract designated as a hedge. If it is determined that the derivative instrument
is not highly effective as a hedge, hedge accounting will be discontinued prospectively. In this case, the gain or loss previously
deferred in accumulated OCI would be frozen until the underlying hedged instrument is delivered unless the transactions being
hedged are no longer probable of occurring in which case the amount in OCI would be immediately reclassified into earnings. If
the derivative instrument is terminated, the effective portion of this derivative deferred in accumulated OCI will be frozen until
the underlying hedged item is delivered.
Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical
transaction is delivered. While these contracts are considered derivative financial instruments under ASC 815, they are not recorded
at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the
scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings.
NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy. These contracts
are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized
in earnings.
Foreign Currency Translation and Transaction Gains and Losses
The local currencies are generally the functional currency of NRG's foreign operations. Foreign currency denominated assets
and liabilities are translated at end-of-period rates of exchange. Revenues, expenses, and cash flows are translated at the weighted-
average rates of exchange for the period. The resulting currency translation adjustments are not included in the Company's
consolidated statements of operations for the period, but are accumulated and reported as a separate component of stockholders'
equity until sale or complete or substantially complete liquidation of the net investment in the foreign entity takes place. Foreign
currency transaction gains or losses are reported within other income/(expense) in the Company's consolidated statements of
operations. For the years ended December 31, 2017, 2016, and 2015, amounts recognized as foreign currency transaction gains
(losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2017, 2016, and 2015
were $(2) million, $(11) million and $(10) million, respectively.
138
139
Concentrations of Credit Risk
Investments Accounted for by the Equity Method
Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of trust funds,
accounts receivable, notes receivable, derivatives, and investments in debt securities. Trust funds are held in accounts managed
by experienced investment advisors. Certain accounts receivable, notes receivable, and derivative instruments are concentrated
within entities engaged in the energy industry. These industry concentrations may impact the Company's overall exposure to credit
risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other
conditions. Receivables and other contractual arrangements are subject to collateral requirements under the terms of enabling
agreements. However, the Company believes that the credit risk posed by industry concentration is offset by the diversification
and creditworthiness of its customer base. See Note 4, Fair Value of Financial Instruments, for a further discussion of derivative
concentrations.
The Company has investments in various domestic energy projects, as well as one Australian project. The equity method
of accounting is applied to such investments in affiliates, which include joint ventures and partnerships, because the ownership
structure prevents the Company from exercising a controlling influence over the operating and financial policies of the projects.
Under this method, equity in pre-tax income or losses of domestic partnerships and, generally, in the net income or losses of its
Australian project, are reflected as equity in earnings of unconsolidated affiliates. For certain investments that relate to tax equity
arrangements, equity earnings are allocated using the hypothetical liquidation at book value, or HLBV, method which is described
below. Distributions from equity method investments that represent earnings on the Company's investment are included within
cash flows from operating activities and distributions from equity method investments that represent a return of the Company's
investment are included within cash flows from investing activities.
Fair Value of Financial Instruments
Tax Equity Arrangements
The carrying amount of cash and cash equivalents, funds deposited by counterparties, receivables, accounts payable, and
accrued liabilities approximate fair value because of the short-term maturity of these instruments. See Note 4, Fair Value of
Financial Instruments, for a further discussion of fair value of financial instruments.
Asset Retirement Obligations
The Company accounts for AROs in accordance with ASC 410-20, Asset Retirement Obligations, or ASC 410-20. Retirement
obligations associated with long-lived assets included within the scope of ASC 410-20 are those for which a legal obligation exists
under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel,
and for which the timing and/or method of settlement may be conditional on a future event. ASC 410-20 requires an entity to
recognize the fair value of a liability for an ARO in the period in which it is incurred and a reasonable estimate of fair value can
be made.
Upon initial recognition of a liability for an ARO, the Company capitalizes the asset retirement cost by increasing the carrying
amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its future value, while the
capitalized cost is depreciated over the useful life of the related asset. See Note 13, Asset Retirement Obligations, for a further
discussion of AROs.
Pensions and Other Postretirement Benefits
The Company offers pension benefits through a defined benefit pension plan. In addition, the Company provides
postretirement health and welfare benefits for certain groups of employees. The Company accounts for pension and other
postretirement benefits in accordance with ASC 715, Compensation — Retirement Benefits. The Company recognizes the funded
status of the Company's defined benefit plans in the statement of financial position and records an offset for gains and losses as
well as all prior service costs that have not been included as part of the Company's net periodic benefit cost to other comprehensive
income. The determination of the Company's obligation and expenses for pension benefits is dependent on the selection of certain
assumptions. These assumptions determined by management include the discount rate, the expected rate of return on plan assets
and the rate of future compensation increases. The Company's actuarial consultants determine assumptions for such items as
retirement age. The assumptions used may differ materially from actual results, which may result in a significant impact to the
amount of pension obligation or expense recorded by the Company.
The Company measures the fair value of its pension assets in accordance with ASC 820, Fair Value Measurements and
Disclosures, or ASC 820.
Stock-Based Compensation
The Company accounts for its stock-based compensation in accordance with ASC 718, Compensation — Stock
Compensation, or ASC 718. The fair value of the Company's non-qualified stock options and market stock units are estimated
on the date of grant using the Black-Scholes option-pricing model and the Monte Carlo valuation model, respectively. NRG uses
the Company's common stock price on the date of grant as the fair value of the Company's restricted stock units and deferred stock
units. Forfeiture rates are estimated based on an analysis of the Company's historical forfeitures, employment turnover, and
expected future behavior. The Company recognizes compensation expense for both graded and cliff vesting awards on a straight-
line basis over the requisite service period for the entire award.
The Company’s redeemable noncontrolling interest in subsidiaries and certain amounts within noncontrolling interest,
included in stockholders' equity, represent third-party interests in the net assets under certain tax equity arrangements, which are
consolidated by the Company, that have been entered into to finance the cost of solar energy systems under operating leases and
wind facilities eligible for certain tax credits. The Company has determined that the provisions in the contractual agreements of
these structures represent substantive profit sharing arrangements. Further, the Company has determined that the appropriate
methodology for calculating the noncontrolling interest and redeemable noncontrolling interest that reflects the substantive profit
sharing arrangements is a balance sheet approach utilizing the HLBV method. Under the HLBV method, the amounts reported
as noncontrolling interest and redeemable noncontrolling interests represent the amounts the investors that are party to the tax
equity arrangements would hypothetically receive at each balance sheet date under the liquidation provisions of the contractual
agreements, assuming the net assets of the funding structures were liquidated at their recorded amounts determined in accordance
with GAAP. The investors’ interests in the results of operations of the funding structures are determined as the difference in
noncontrolling interest and redeemable noncontrolling interests at the start and end of each reporting period, after taking into
account any capital transactions between the structures and the funds’ investors. The calculations utilized to apply the HLBV
method include estimated calculations of taxable income or losses for each reporting period.
Redeemable Noncontrolling Interest
To the extent that the third-party has the right to redeem their interests for cash or other assets, the Company has included
the noncontrolling interest attributable to the third party as a component of temporary equity in the mezzanine section of the
consolidated balance sheet. The following table reflects the changes in the Company's redeemable noncontrolling interest balance
for the years ended December 31, 2017, 2016, and 2015.
Balance as of December 31, 2014
Cash contributions from redeemable noncontrolling interest
Comprehensive loss attributable to redeemable noncontrolling interest
Balance as of December 31, 2015
Distributions to redeemable noncontrolling interest
Contributions from redeemable noncontrolling interest
Non-cash adjustments to redeemable noncontrolling interest
Comprehensive loss attributable to redeemable noncontrolling interest
Balance as of December 31, 2016
Distributions to redeemable noncontrolling interest
Contributions from redeemable noncontrolling interest
Non-cash adjustments to redeemable noncontrolling interest
Comprehensive loss attributable to redeemable noncontrolling interest
Balance as of December 31, 2017
(In millions)
$
$
19
27
(17)
29
(1)
33
23
(38)
46
(2)
99
7
(72)
78
140
141
Sale-Leaseback Arrangements
Recent Accounting Developments - Guidance Adopted in 2017
NRG is party to sale-leaseback arrangements that provide for the sale of certain assets to a third party and simultaneous
leaseback to the Company. In accordance with ASC 840-40, Sale-Leaseback Transactions, if the seller-lessee retains, through the
leaseback, substantially all of the benefits and risks incident to the ownership of the property sold, the sale-leaseback transaction
is accounted for as a financing arrangement. An example of this type of continuing involvement would include an option to
repurchase the assets or the buyer-lessor having the option to sell the assets back to the Company. This provision is included in
most of the Company’s sale-leaseback arrangements. As such, the Company accounts for these arrangements as financings.
Under the financing method, the Company does not recognize as income any of the sale proceeds received from the lessor
that contractually constitutes payment to acquire the assets subject to these arrangements. Instead, the sale proceeds received are
accounted for as financing obligations and leaseback payments made by the Company are allocated between interest expense and
as a reduction to the financing obligation. Interest on the financing obligation is calculated using the Company’s incremental
borrowing rate at the inception of the arrangement on the outstanding financing obligation. Judgment is required to determine
the appropriate borrowing rate for the arrangement and in determining any gain or loss on the transaction that would be recorded
either at the end of or over the lease term.
Marketing and Advertising Costs
The Company expenses its marketing and advertising costs as incurred and which are included within selling, general and
administrative expenses. Marketing and advertising expenses for the years ended December 31, 2017, 2016, and 2015 were $184
million, $247 million, and $309 million, respectively. The costs of tangible assets used in advertising campaigns are recorded as
fixed assets or deferred advertising costs and amortized as advertising costs over the shorter of the useful life of the asset or the
advertising campaign. The Company has several long-term sponsorship arrangements. Payments related to these arrangements
are deferred and expensed over the term of the arrangement. Advertising expenses for the years ended December 31, 2017, 2016,
and 2015 were $42 million, $53 million, and $135 million, respectively.
Reorganization Costs
Reorganization costs include costs incurred by the Company related to the Transformation Plan implementation and primarily
reflect personnel costs related to cost savings initiatives. As of December 31, 2017, $44 million has been incurred.
Business Combinations
The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, or ASC 805.
ASC 805 requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities
assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also recognizes and measures the
goodwill acquired or a gain from a bargain purchase in the business combination and determines what information to disclose to
enable users of an entity's financial statements to evaluate the nature and financial effects of the business combination. In addition,
transaction costs are expensed as incurred.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States
requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of
the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported
amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.
In recording transactions and balances resulting from business operations, the Company uses estimates based on the best
information available. Estimates are used for such items as plant depreciable lives, tax provisions, uncollectible accounts, actuarially
determined benefit costs, the valuation of energy commodity contracts, environmental liabilities, legal costs incurred in connection
with recorded loss contingencies, and assets acquired and liabilities assumed in business combinations, among others. In addition,
estimates are used to test long-lived assets and goodwill for impairment and to determine the fair value of impaired assets. As
better information becomes available or actual amounts are determinable, the recorded estimates are revised. Consequently,
operating results can be affected by revisions to prior accounting estimates.
Reclassifications
Certain prior-year amounts have been reclassified for comparative purposes. The reclassifications did not affect results from
operations, net assets or cash flows.
ASU 2018-02 — In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income
(Topic 220), Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, or ASU No. 2018-02. Prior
to ASU No. 2018-02, GAAP required the remeasurement of deferred tax assets and liabilities as a result of a change in tax laws
or rates to be presented in net income from continuing operations, even in situations in which the related income tax effects of
items in accumulated other comprehensive income were originally recognized in other comprehensive income. As a result, such
items, referred to as stranded tax effects, did not reflect the appropriate tax rate. Under ASU No. 2018-02, entities are permitted,
but not required, to reclassify from accumulated other comprehensive income to retained earnings those stranded tax effects
resulting from the Tax Act. ASU No. 2018-02 is effective for all entities for fiscal years beginning after December 15, 2018, and
interim periods within those fiscal years. Early adoption is permitted. The Company adopted the new standard effective December
31, 2017. As a result of the adoption, the Company reclassified $13 million from accumulated other comprehensive loss to retained
earnings in the consolidated balance sheet as of December 31, 2017.
ASU 2017-12 — In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815), Targeted
Improvements to Accounting for Hedging Activities, or ASU No. 2017-12. The amendments of ASU No. 2017-12 were issued to
simplify the application of hedge accounting guidance and more closely align financial reporting for hedging relationships with
economic results of an entity's risk management activities. The issues addressed by ASU No. 2017-12 include but are not limited
to alignment of risk management activities and financial reporting, risk component hedging, accounting for the hedged item in
fair value hedges of interest rate risk, recognition and presentation of the effects of hedging instruments, amounts excluded from
the assessment of hedge effectiveness, and other simplifications of hedge accounting guidance. The Company adopted the guidance
in ASU No. 2017-12 during the fourth quarter of 2017, with no material adjustments recorded to the consolidated results of
operations, cash flows, and statement of financial position.
ASU 2016-18 — In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230), Restricted
Cash, or ASU No. 2016-18. The amendments of ASU No. 2016-18 require an entity to include amounts generally described as
restricted cash and restricted cash equivalents, including funds deposited by counterparties with cash and cash equivalents when
reconciling the beginning of period and end of period total amounts on the statement of cash flows. The amendments of ASU No.
2016-18 are effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual
periods. Early adoption is permitted and the adoption of ASU No. 2016-18 will be applied retrospectively. The Company adopted
the guidance in ASU No. 2016-18 during the second quarter of 2017. In connection with the adoption of the standard, the Company
has applied the guidance retrospectively which resulted in a (decrease)/increase in cash flows from operations of $(53) million
and $37 million and an increase/(decrease) in cash flows from investing of $32 million and $(43) million on the statement of cash
flows for the years ended December 31, 2016 and 2015, respectively.
ASU 2016-16 — In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of
Assets Other Than Inventory, or ASU No. 2016-16. Previous GAAP prohibited the recognition of current and deferred income
taxes for an intra-entity asset transfer until the asset has been sold to an outside party which has resulted in diversity in practice
and increased complexity within financial reporting. The amendments of ASU No. 2016-16 require an entity to recognize the
income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company
adopted the guidance in ASU No. 2016-16 effective January 1, 2017. In connection with the adoption of the standard, the Company
recorded a reduction to non-current assets of $267 million with a corresponding reduction to cumulative retained deficit as of
December 31, 2017.
ASU 2016-15 — In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), Classification
of Certain Cash Receipts and Cash Payments, or ASU No. 2016-15. The amendments of ASU No. 2016-15 were issued to address
eight specific cash flow issues for which stakeholders have indicated to the FASB that a diversity in practice existed in how entities
were presenting and classifying these items in the statement of cash flows. The issues addressed by ASU No. 2016-15 include but
are not limited to the classification of debt prepayment and debt extinguishment costs, payments made for contingent consideration
for a business combination, proceeds from the settlement of insurance proceeds, distributions received from equity method investees
and separately identifiable cash flows and the application of the predominance principle. The Company adopted the guidance in
ASU No. 2016-15 effective January 1, 2017. In connection with the adoption of the standard, the Company has applied the guidance
retrospectively which resulted in an increase in cash flows from operations of $121 million and a decrease in cash flows from
financing of $121 million on the statement of cash flows for the year ended December 31, 2016. There was no impact to the
statement of cash flows for the year ended December 31, 2015, as a result of adoption.
142
143
ASU 2016-09 — In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718), or
ASU No. 2016-09. The amendments focused on simplification specifically with regard to share-based payment transactions,
including income tax consequences, classification of awards as equity or liabilities and classification on the statement of cash
flows. The Company adopted the guidance in ASU No. 2016-09 effective January 1, 2017, with no material adjustments recorded
to the Company's consolidated financial statements.
By eliminating a large portion of its operations in the PJM market with the deconsolidation of GenOn, NRG concluded that
GenOn meets the criteria for discontinued operations, as this represents a strategic shift in the markets in which NRG operates.
As such, all prior period results for GenOn have been reclassified as discontinued operations while NRG will record all ongoing
results of GenOn as a cost method investment, which was valued at zero at the date of deconsolidation.
Summarized results of discontinued operations were as follows:
Recent Accounting Developments - Guidance Not Yet Adopted
ASU 2017-07 — In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715),
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, or ASU No. 2017-07.
Current GAAP does not indicate where the amount of net benefit cost should be presented in an entity’s income statement and
does not require entities to disclose the amount of net benefit cost that is included in the income statement. The amendments of
ASU No. 2017-07 require an entity to report the service cost component of net benefit costs in the same line item as other
compensation costs arising from services rendered by the related employees during the applicable service period. The other
components of net benefit cost are required to be presented separately from the service cost component and outside the subtotal
of income from operations. Further, ASU No. 2017-07 prescribes that only the service cost component of net benefit costs is
eligible for capitalization. The Company adopted the amendments of ASU No. 2017-07 effective January 1, 2018. The adoption
of ASU No. 2017-07 will not have a material impact on the Company's results of operations, cash flows, and statement of financial
position.
ASU 2016-02 — In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or Topic 842, with the objective
to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance
sheet and to improve financial reporting by expanding the related disclosures. The guidance in Topic 842 provides that a lessee
that may have previously accounted for a lease as an operating lease under current GAAP should recognize the assets and liabilities
that arise from a lease on the balance sheet. In addition, Topic 842 expands the required quantitative and qualitative disclosures
with regards to lease arrangements. The Company will adopt the standard effective January 1, 2019, and expects to elect certain
of the practical expedients permitted, including the expedient that permits the Company to retain its existing lease assessment and
classification. The Company is currently working through an adoption plan which includes the evaluation of lease contracts
compared to the new standard. While the Company is currently evaluating the impact the new guidance will have on its financial
position and results of operations, the Company expects to recognize lease liabilities and right of use assets. The extent of the
increase to assets and liabilities associated with these amounts remains to be determined pending the Company’s review of its
existing lease contracts and service contracts which may contain embedded leases. While this review is still in process, NRG
believes the adoption of Topic 842 will have a material impact on its financial statements. The Company is continuing to monitor
potential changes to Topic 842 that have been proposed by the FASB and will assess any necessary changes to the implementation
process as the guidance is updated.
ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or
Topic 606, which was further amended through various updates issued by the FASB thereafter. The amendments of Topic 606
completed the joint effort between the FASB and the IASB, to develop a common revenue standard for GAAP and IFRS, and to
improve financial reporting. The guidance under Topic 606 provides that an entity should recognize revenue to depict the transfer
of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in
exchange for the goods or services provided and establishes a five step model to be applied by an entity in evaluating its contracts
with customers. The Company has also elected the practical expedient available under Topic 606 for measuring progress toward
complete satisfaction of a performance obligation and for disclosure requirements of remaining performance obligations. The
practical expedient allows an entity to recognize revenue in the amount to which the entity has the right to invoice such that the
entity has a right to the consideration in an amount that corresponds directly with the value to the customer for performance
completed to date by the entity. The Company adopted the standard effective January 1, 2018. The adoption of Topic 606 at the
date of initial application, as prescribed under the modified retrospective transition method, will not have a material impact on
the Company's financial statements. The adoption of Topic 606 also includes additional disclosure requirements beginning in the
first quarter of 2018. Many of these disclosures are not substantially different than the Company's existing disclosures. Topic 606
requires disclosure of disaggregated revenue amounts, which the Company expects would include types of operating revenues by
business.
Note 3 — Discontinued Operations, Acquisitions and Dispositions
Discontinued Operations
As described in Note 1, Nature of Business, on the Petition Date, the GenOn Entities filed voluntary petitions for relief under
Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. As a result of the bankruptcy filings, NRG concluded that it no longer
controls GenOn as it is subject to the control of the Bankruptcy Court; and, accordingly, NRG no longer consolidates GenOn for
financial reporting purposes.
(In millions)
Operating revenues
Operating costs and expenses
Gain on sale of assets
Other expenses
(Loss)/Income from operations of discontinued components, before tax
Income tax expense
(Loss)/Income from operations of discontinued components
Interest income - affiliate
(Loss)/Income from operations of discontinued components, net of tax
Pre-tax loss on deconsolidation
Settlement consideration and services credit
Pension and post-retirement liability assumption
Other
Loss on disposal of discontinued components, net of tax
(Loss)/Income from discontinued operations, net of tax
Year ended December 31,
2017
2016
$
646
(702)
—
(98)
(154)
9
(163)
8
(155)
(208)
(289)
(131)
(6)
(634)
(789) $
1,862
(1,896)
294
(168)
92
11
81
11
92
—
—
—
—
—
92
$
$
The following table summarizes the major classes of assets and liabilities classified as discontinued operations as of
December 31, 2016. As of June 14, 2017, NRG no longer consolidates GenOn for financial reporting purposes.
(In millions)
Cash and cash equivalents
Other current assets
Current assets - discontinued operations
Property, plant and equipment, net
Other non-current assets
Non-current assets - discontinued operations
Current portion of long term debt and capital leases
Other current liabilities
Current liabilities - discontinued operations
Long-term debt and capital leases
Out-of-market contracts
Other non-current liabilities
Non-current liabilities - discontinued operations
Chapter 11 Cases
December 31, 2016
1,034
885
1,919
2,543
418
2,961
704
506
1,210
2,050
811
323
3,184
$
$
Prior to the GenOn Entities' filing the Chapter 11 Cases, on June 12, 2017, NRG entered into a restructuring support and
lock-up agreement, or the Restructuring Support Agreement, with the GenOn Entities and certain holders of the GenOn and GenOn
Americas Generation Senior Notes, that provides for a restructuring and recapitalization of the GenOn Entities through a prearranged
plan of reorganization. There is no assurance that the GenOn Entities' plan will be successfully implemented. The principal terms
of the Restructuring Support Agreement are described further below.
144
145
On September 18, 2017, and October 2, 2017, the GenOn Entities filed amendments to the plan of reorganization and the
disclosure statement which primarily provided the GenOn Entities with the flexibility to complete sales of certain assets pursuant
to the amended plan of reorganization and removed the GenOn Entities' requirement to conduct a rights offering in connection
with the GenOn Entities' exit financing.
and the letter of credit facility obtained in July 2017.
8) NRG and GenOn have agreed to cooperate in good faith to maximize the value of certain development projects.
Pursuant to this, GenOn made a one-time payment in the amount of $15 million to NRG in December 2017 as
compensation for a purchase option with respect to the Canal 3 project.
On October 31, 2017, the GenOn Entities announced that they entered into a Consent Agreement with certain holders of
GenOn’s Senior Notes and GenOn Americas Generation's Senior Notes, collectively, the Consenting Holders, whereby the GenOn
Entities and the Consenting Holders agreed to extend the milestones in the Restructuring Support Agreement, by which the plan
of reorganization must become effective, or the Effective Date. Specifically, the Consent Agreement extended the Effective Date
milestone to June 30, 2018, or September 30, 2018, if regulatory approvals are still pending, or the Extended Effective Dates.
On December 12, 2017, the Bankruptcy Court entered an order confirming the plan of reorganization, and effective December
12, 2017, GenOn and NRG entered into agreements concerning (i) timeline and transition, (ii) cooperation and co-development
matters, (iii) post-employment and retiree health and welfare benefits and pension benefits, (iv) tax matters, and (v) intercompany
balances and releases, consistent with the Restructuring Support Agreement, which among other things, provide for the transition
of GenOn to a standalone enterprise, the resolution of substantial intercompany claims between GenOn and NRG, and the allocation
of certain costs and liabilities between GenOn and NRG. On December 12, 2017, the Bankruptcy Court also entered an order
giving effect to the Consent Agreement.
Forms of certain of the definitive documents that make up the plan supplement were filed with the Bankruptcy Court by the
GenOn Entities and approved by the Bankruptcy Court in connection with the confirmation of the plan of reorganization. It is a
condition precedent to the occurrence of the effective date of the plan of reorganization that the final version of the plan supplement
be consistent with the Restructuring Support Agreement, in all material respects.
Restructuring Support Agreement
As described in Note 1, Nature of Business, NRG, GenOn and certain holders representing greater than 93% in aggregate
principal amount of GenOn’s Senior Notes and certain holders representing greater than 93% in aggregate principal amount of
GenOn Americas Generation’s Senior Notes entered into a Restructuring Support Agreement that provides for a restructuring and
recapitalization of the GenOn Entities through a prearranged plan of reorganization that was approved by the Bankruptcy Court
pursuant to an order of confirmation. Completion of the agreed upon terms is contingent upon certain milestones in the Restructuring
Support Agreement and the satisfaction or waiver or certain conditions precedent. Certain principal terms of the Restructuring
Support Agreement and the plan of reorganization are detailed below:
1) The dismissal of litigation and full releases from GenOn and GenOn Americas Generation in favor of NRG upon the
earlier of the consummation of the GenOn Entities' plan of reorganization or the Settlement Agreement; a condition
precedent to the consummation of the Settlement Agreement is a full release or indemnification in favor of NRG from
any claims of GenOn Mid-Atlantic and REMA.
2) NRG will provide settlement cash consideration to GenOn of $261.3 million, which will be paid in cash less any
amounts owed to NRG under the intercompany secured revolving credit facility. As of December 31, 2017, GenOn
owed NRG approximately $125 million under the intercompany secured revolving credit facility. See Note 21, Related
Party Transactions, for further discussion of the intercompany secured revolving credit facility.
3) NRG will consent to the cancellation of its interests in the equity of GenOn and be entitled to a worthless stock
deduction, as further described in the tax matters agreement. The equity interests in the reorganized GenOn will be
issued to the holders of the GenOn Senior Notes.
4) NRG will retain the pension liability, including payment of approximately $13 million of 2017 pension contributions,
for GenOn employees for service provided prior to the completion of the reorganization, which was paid in September
2017. GenOn’s pension liability as of December 31, 2017, was approximately $92 million. NRG will also retain the
liability for GenOn’s post-employment and retiree health and welfare benefits, in an amount up to $25 million.
5) The shared services agreement between NRG and GenOn was terminated and replaced as of the plan confirmation
date with a transition services agreement. Under the transition services agreement, NRG will continue to provide the
shared services and other separation services at an annualized rate of $84 million, subject to certain credits and
adjustments. See Note 21, Related Party Transactions, for further discussion of the Services Agreement.
6) NRG will provide a credit of $28 million to GenOn to apply against amounts owed under the transition services
agreement. Any unused amount can be paid in cash at GenOn’s request. The credit was intended to reimburse GenOn
for its payment of financing costs.
7) NRG agreed to provide GenOn with a letter of credit facility during the pendency of the Chapter 11 Cases, which
could be utilized for required letters of credit in lieu of the intercompany secured revolving credit facility. GenOn
can no longer utilize the intercompany secured revolving credit facility and, on July 27, 2017, the letter of credit
facility was terminated, as GenOn had obtained a separate letter of credit facility with a third party financial institution.
See Note 21, Related Party Transactions, for further discussion of the intercompany secured revolver credit facility
Settlement Consideration
NRG has determined that the payment of the settlement consideration is probable and has recorded a liability for the amount
due of $261.3 million in accrued expenses and other current liabilities - affiliate with a corresponding loss from discontinued
operations. NRG expects to pay this amount net of amounts due from GenOn under the intercompany secured revolving credit
facility, which is further described in Note 21, Related Party Transactions.
Pension Liability
NRG will retain the pension liability, including payment of approximately $13 million of 2017 pension contributions, which
was paid in September 2017, for the GenOn employees for service provided prior to emergence from bankruptcy. NRG determined
that the retention of this liability is probable and has recorded the estimated accumulated pension benefit obligation as of December
31, 2017 of $92 million in other non-current liabilities with a corresponding loss from discontinued operations. NRG's obligation
for this liability will be revalued through and at GenOn's emergence from bankruptcy.
Services Agreement
In December 2017, in conjunction with the confirmation of the GenOn Entities' plan of reorganization, the Services Agreement
was terminated and replaced by the transition services agreement. Under the transition services agreement, NRG will continue to
provide shared services and other separation services to GenOn at an annualized rate of $84 million until June 30, 2018, which
may be extended by GenOn through September 30, 2018. NRG may provide additional separation services that are necessary for
or reasonably related to the operation of GenOn's business after such date, subject to NRG's prior written consent, not to be
unreasonably withheld.
Beginning on June 14, 2017, and through December 2017, NRG recorded amounts earned for shared services of approximately
$5 million per month. In December 2017, NRG provided GenOn with a $3.5 million credit for services provided under the transition
services agreement and began recording amounts earned for shared services of approximately $7 million per month. NRG has
also agreed to provide GenOn with a credit of $28 million against amounts owed under the transition services agreement. Any
unused amount can be paid in cash at GenOn’s request, subject to the terms and conditions of the transition services agreement.
As a result, NRG has concluded that the liability for this credit is probable and has recorded a payable to GenOn for $28 million
in accrued expenses and other current liabilities - affiliate with a corresponding loss from discontinued operations.
Commercial Operations
For pre-disposal periods, NRG provided GenOn with services as described in Note 21, Related Party Transactions. Under
intercompany agreements, NRG Power Marketing LLC has entered into physical and financial intercompany commodity and
hedging transactions with GenOn and certain of its subsidiaries. Subject to applicable collateral thresholds, these arrangements
may provide for the bilateral exchange of credit support based upon market exposure and potential market movements. The terms
and conditions of the agreements are generally consistent with industry practices and other third party arrangements. For current
and pre-disposal periods, revenue and expense associated with these transactions is recorded in continuing operations.
GenOn Debt
As of June 14, 2017, the GenOn Senior Notes and GenOn Americas Generation Senior Notes, which totaled approximately
$2.5 billion, were deconsolidated from NRG's consolidated financial statements. The filing of the Chapter 11 Cases constitutes
an event of default under the following debt instruments of GenOn:
1) The intercompany secured revolving credit facility with NRG;
2) The indenture governing the GenOn 7.875% Senior Notes due 2017 (as amended or supplemented from time to time);
3) The indenture governing the GenOn 9.500% Notes due 2018 (as amended or supplemented from time to time);
4) The indenture governing the GenOn 9.875% Notes due 2020 (as amended or supplemented from time to time);
5) The indenture governing the GenOn Americas Generation 8.50% Senior Notes due 2021 (as amended or supplemented
from time to time); and
6) The indenture governing the GenOn Americas Generation 9.125% Senior Notes due 2031 (as amended or supplemented
from time to time).
146
147
Dispositions
2016 Disposition of Majority Interest in EVgo
On June 17, 2016, the Company completed the sale of a majority interest in its EVgo business to Vision Ridge Partners for
total consideration of approximately $39 million, including $17 million in cash received, which is net of $2.5 million in working
capital adjustments, $15 million contributed as capital to the EVgo business and $7 million of future contributions by Vision Ridge
Partners, all of which were determined based on forecasted cash requirements to operate the business in future periods. In addition,
the Company has future earnout potential of up to $70 million based on future profitability targets. NRG retained its original
financial obligation of $102.5 million under its agreement with the CPUC whereby EVgo will build at least 200 public fast charging
Freedom Station sites and perform the associated work to prepare 10,000 commercial and multi-family parking spaces for electric
vehicle charging in California. As part of the sale, NRG has contracted with EVgo to continue to build the remaining required
Freedom Stations and commercial and multi-family parking spaces for electric vehicle charging required under this obligation
and EVgo will be directly reimbursed by NRG for the costs. As a result of the sale, the Company recorded a loss on sale of $78
million during the second quarter of 2016, which reflects the loss on the sale of the equity interest of $27 million and the accrual
of NRG's remaining obligation under its agreement with the CPUC of $56 million, of which $25 million remains as of December
31, 2017. On February 22, 2017, the Company and CPUC entered into a second amendment to the agreement which extended
the operating period commitment for the Freedom Stations to December 5, 2020. As of December 31, 2017, the Company's
remaining 35% interest in EVgo of $1 million was accounted for as an equity method investment.
2016 Rockford Disposition
On May 12, 2016, the Company entered into an agreement with RA Generation, LLC to sell 100% of its interests in the
Rockford I and Rockford II generating stations, or Rockford, for cash consideration of $55 million, subject to adjustments for
working capital and the results of the PJM 2019/2020 base residual auction. Rockford is a 450-MW natural gas facility located
in Rockford, Illinois. The transaction triggered an indicator of impairment as the sales price was less than the carrying amount of
the assets and, as a result, the assets were considered to be impaired. The Company measured the impairment loss as the difference
between the carrying amount of the assets and the agreed-upon sales price. The Company recorded an impairment loss of $17
million during the quarter ended June 30, 2016 to reduce the carrying amount of the assets held for sale to the fair market value.
On July 12, 2016, the Company completed the sale of Rockford for cash proceeds of $56 million, including $1 million in adjustments
for the PJM base residual auction results. For further discussion on this impairment, refer to Note 10, Asset Impairments.
2015 Disposition of Altenex
On December 31, 2015, the Company completed the sale of its 32% interest in Altenex, LLC to Edison Energy, LLC and
Edison Energy NewCo 2, LLC for cash consideration of $26 million. The Company had accounted for its investment in Altenex
as an equity method investment and recognized a loss of $14 million as a result of the transactions within the Company's consolidated
statements of operations.
Acquisitions
2016 Utility-Scale Solar and Wind Acquisition
On November 2, 2016, the Company acquired equity interests in a tax equity portfolio from SunEdison, located in Utah,
comprised of 530 MW of mechanically-complete solar assets, of which NRG’s net interest based on cash to be distributed is 265
MW, for upfront cash consideration of $111 million. In connection with the acquisition, the Company assumed non-recourse debt
of $222 million. The Company also borrowed additional amounts of $65 million during the fourth quarter of 2016, as described
in Note 12, Debt and Capital Leases, which effectively reduced the Company's use of liquidity related to the acquisition. The
Company does not have a controlling interest in the tax equity portfolio and, accordingly, its interest is recorded as an equity
method investment. The purchase price was allocated to the equity method investment balance of approximately $328 million,
current assets of $5 million and the assumed non-recourse debt of $222 million. The assets reached commercial operations during
the fourth quarter of 2016 and have 20-year PPAs with PacifiCorp.
The Company acquired a 110-MW portfolio of construction-ready and 71 MW of development solar assets in Hawaii from
SunEdison for upfront cash consideration of $2 million on October 3, 2016, and a 154-MW construction-ready solar project in
Texas for upfront cash consideration of $11 million on November 9, 2016.
In addition to the total $124 million in upfront cash consideration paid for the above acquisitions, the Company expects to
make an estimated $59 million in additional payments contingent upon future development milestones, of which $20 million was
paid as of December 31, 2017.
2016 Solar Distributed Generation Acquisition
On October 3, 2016, the Company acquired a 29-MW portfolio of mechanically-complete and construction-ready distributed
generation solar assets from SunEdison for cash consideration of approximately $67 million excluding post-closing adjustments
which reduced the purchase price by $5 million. Subsequent to the acquisition, the Company sold these assets into a tax-equity
financed portfolio within the DGPV Holdco partnership between NRG and NRG Yield, Inc. The purchase price was allocated to
$47 million in construction in progress and $15 million in intangible assets.
2015 Acquisition of Desert Sunlight
On June 29, 2015, NRG Yield, Inc., through its subsidiary NRG Yield Operating LLC, acquired 25% of the membership
interest in Desert Sunlight Investment Holdings, LLC, which owns two solar photovoltaic facilities that total 550 MW located in
Desert Center, California from EFS Desert Sun, LLC, an affiliate of GE Energy Financial Services, for a purchase price of $285
million. The Company accounts for its 25% investment as an equity method investment.
Transfers of Assets under Common Control
On November 1, 2017, NRG completed the sale of a 38-MW solar portfolio primarily comprised of assets from SPP funds,
in addition to other projects developed by NRG, to NRG Yield, Inc. for cash consideration of $71 million, plus $3 million in
working capital adjustments.
On August 1, 2017, NRG closed on the sale of its remaining 25% interest in NRG Wind TE Holdco, a portfolio of 12 wind
projects, to NRG Yield, Inc. for total cash consideration of $44 million, including working capital adjustment of $3 million. The
transaction also includes potential additional payments to NRG dependent upon actual energy prices for merchant periods beginning
in 2027.
On March 27, 2017, the Company sold to NRG Yield, Inc.: (i) a 16% interest in the Agua Caliente solar project, representing
ownership of approximately 46 net MW of capacity and (ii) NRG's interests in seven utility-scale solar projects located in Utah
representing 265 net MW of capacity, which have reached commercial operations. NRG Yield, Inc. paid cash consideration of
$130 million, plus $1 million in working capital adjustments, and assumed non-recourse debt of approximately $328 million.
On September 1, 2016, the Company completed the sale of its remaining 51.05% interest in the CVSR project to NRG Yield,
Inc. for total cash consideration of $78.5 million, plus an immaterial working capital adjustment. In addition, NRG Yield, Inc.
assumed non-recourse project level debt of $496 million.
On November 3, 2015, the Company sold 75% of the Class B interests of NRG Wind TE Holdco, which owns a portfolio
of 12 wind facilities totaling 814 net MW, to NRG Yield, Inc. NRG Yield, Inc. paid total cash consideration of $209 million,
subject to working capital adjustments. NRG Yield, Inc. is responsible for its pro-rata share of non-recourse project debt of $193
million and noncontrolling interest associated with a tax equity structure of $159 million (as of the acquisition date). In February
2016, the Company made a final working capital payment of $2 million to NRG Yield, Inc. reducing total cash consideration to
$207 million.
On January 2, 2015, the Company sold the following facilities to NRG Yield, Inc.: Walnut Creek, the Tapestry projects
(Buffalo Bear, Pinnacle and Taloga) and Laredo Ridge. NRG Yield, Inc. paid total cash consideration of $489 million, including
$9 million of working capital adjustments, plus assumed project level debt of $737 million.
The above sales were recorded as transfers of entities under common control and the related assets were transferred at their
carrying value.
148
149
Note 4 — Fair Value of Financial Instruments
Recurring Fair Value Measurements
For cash and cash equivalents, funds deposited by counterparties, accounts and other receivables, accounts payable, restricted
cash, and cash collateral posted and received in support of energy risk management activities, the carrying amount approximates
fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.
Debt securities, equity securities, and trust fund investments, which are comprised of various U.S. debt and equity securities,
and derivative assets and liabilities, are carried at fair market value.
The following tables present assets and liabilities measured and recorded at fair value on the Company's consolidated balance
The estimated carrying values and fair values of the Company's recorded financial instruments not carried at fair market
sheets on a recurring basis and their level within the fair value hierarchy:
value are as follows:
Assets
Notes receivable (a)
Liabilities
Long-term debt, including current portion (b)
As of December 31,
2017
2016
Carrying Amount
Fair Value
Carrying Amount
Fair Value
(In millions)
$
$
16
16,603
$
$
15
16,894
$
$
34
16,655
$
$
34
16,620
(a) Includes the current portion of notes receivable which is recorded in prepayments and other current assets on the Company's consolidated balance sheets.
(b) Excludes deferred financing costs, which are recorded as a reduction to long-term debt on the Company's consolidated balance sheets.
The fair value of the Company's publicly-traded long-term debt is based on quoted market prices and is classified as Level
2 within the fair value hierarchy. The fair value of debt securities, non-publicly traded long-term debt, and certain notes receivable
of the Company are based on expected future cash flows discounted at market interest rates or current interest rates for similar
instruments with equivalent credit quality and are classified as Level 3 within the fair value hierarchy. The following table presents
the level within the fair value hierarchy for long-term debt, including current portion as of December 31, 2017 and 2016:
Long-term debt, including current portion
$
8,934
$
(In millions)
$
7,960
9,205
$
7,415
As of December 31, 2017
As of December 31, 2016
Level 2
Level 3
Level 2
Level 3
Fair Value Accounting under ASC 820
ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into
three levels as follows:
• Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Company has the ability
to access as of the measurement date. NRG's financial assets and liabilities utilizing Level 1 inputs include active exchange-
traded securities, energy derivatives, and trust fund investments.
• Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability
or indirectly observable through corroboration with observable market data. NRG's financial assets and liabilities utilizing
Level 2 inputs include fixed income securities, exchange-based derivatives, and over the counter derivatives such as
swaps, options and forward contracts.
• Level 3 — unobservable inputs for the asset or liability only used when there is little, if any, market activity for the asset
or liability at the measurement date. NRG's financial assets and liabilities utilizing Level 3 inputs include infrequently-
traded, non-exchange-based derivatives and commingled investment funds, and are measured using present value pricing
models.
In accordance with ASC 820, the Company determines the level in the fair value hierarchy within which each fair value
measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety.
Investments in securities (classified within other non-current assets):
Debt securities
Available-for-sale securities
Nuclear trust fund investments:
Cash and cash equivalents
U.S. government and federal agency obligations
Federal agency mortgage-backed securities
Commercial mortgage-backed securities
Corporate debt securities
Equity securities
Foreign government fixed income securities
Other trust fund investments:
U.S. government and federal agency obligations
Derivative assets:
Commodity contracts
Interest rate contracts
Measured using net asset value practical expedient:
Equity securities
Total assets
Derivative liabilities:
Commodity contracts
Interest rate contracts
Total liabilities
As of December 31, 2017
Fair Value
Total
Level 1
Level 2
Level 3
(In millions)
$
$
19
3
— $
3
— $
—
47
43
82
14
99
334
5
1
745
53
68
1,513
693
59
752
$
$
$
$
$
$
45
42
—
—
—
334
—
1
191
—
616
257
—
257
$
$
$
2
1
82
14
99
—
5
—
509
53
765
359
59
418
$
$
$
19
—
—
—
—
—
—
—
—
—
45
—
64
77
—
77
150
151
Investments in securities (classified within other non-current assets):
Debt securities
Available-for-sale securities
Nuclear trust fund investments:
Cash and cash equivalents
U.S. government and federal agency obligations
Federal agency mortgage-backed securities
Commercial mortgage-backed securities
Corporate debt securities
Equity securities
Foreign government fixed income securities
Other trust fund investments:
U.S. government and federal agency obligations
Derivative assets:
Commodity contracts
Interest rate contracts
Measured using net asset value practical expedient:
Equity securities
Total assets
Derivative liabilities:
Commodity contracts
Interest rate contracts
Total liabilities
As of December 31, 2016
Fair Value
Total
Level 1
Level 2
Level 3
$
$
17
10
— $
10
— $
—
25
73
62
17
84
292
3
1
1,199
49
54
1,886
1,288
88
1,376
$
$
$
$
$
$
25
72
—
—
—
292
—
1
560
—
960
494
—
494
$
$
$
—
1
62
17
84
—
3
—
549
49
765
636
88
724
17
—
—
—
—
—
—
—
—
—
90
—
$
$
$
107
158
—
158
There have been no transfers during the year ended December 31, 2017 between Levels 1 and 2. The following tables
reconcile, for the years ended December 31, 2017 and 2016, the beginning and ending balances for financial instruments that are
recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs:
Beginning balance as of January 1, 2017
Total gains/(losses) realized/unrealized:
Included in earnings
Included in nuclear decommissioning obligations
Purchases
Contracts reclassified to held-for-sale
Transfers into Level 3 (b)
Transfers out of Level 3 (b)
Ending balance as of December 31, 2017
Gains for the period included in earnings attributable to the change in
unrealized gains or losses relating to assets or liabilities still held as of
December 31, 2017
$
$
(a) Consists of derivatives assets and liabilities, net.
For the Year Ended December 31, 2017
Fair Value Measurement Using Significant
Unobservable Inputs (Level 3)
Debt
Securities
Derivatives (a)
(In millions)
Total
$
17
$
(68) $
2
—
—
—
—
—
19
$
43
—
(23)
4
(1)
13
(32) $
(51)
45
—
(23)
4
(1)
13
(13)
2
$
6
$
8
Beginning balance as of January 1, 2016
$
17
$
54
$
(22) $
For the Year Ended December 31, 2016
Fair Value Measurement Using Significant Unobservable Inputs
(Level 3)
Debt
Securities
Trust Fund
Investments (c)
Derivatives (a)
Total
(In millions)
Total gains/(losses) realized/unrealized:
Included in earnings
Included in nuclear decommissioning obligations
Purchases
Transfers into Level 3 (b)
Transfer out of Level 3 (b)
Ending balance as of December 31, 2016
Losses for the period included in earnings attributable to the
change in unrealized gains or losses relating to assets or
liabilities still held as of December 31, 2016
$
$
—
—
—
—
—
17
$
—
(1)
1
—
(54)
— $
2
—
(29)
(18)
(1)
(68) $
49
2
(1)
(28)
(18)
(55)
(51)
— $
— $
(13) $
(13)
(a) Consists of derivatives assets and liabilities, net.
(b) Transfers into/out of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers
into/out of Level 3 are from/to Level 2.
(c) All Trust Fund Investments were considered transferred out of Level 3 as these investments are measured using net asset value as a practical expedient
and are thus classified outside of the fair value hierarchy as of December 31, 2016.
Realized and unrealized gains and losses included in earnings that are related to the energy derivatives are recorded in
operating revenues and cost of operations.
Non-derivative fair value measurements
NRG's investments in debt securities are classified as Level 3 and consist of non-traded debt instruments that are valued
based on third-party market value assessments.
The trust fund investments are held primarily to satisfy NRG's nuclear decommissioning obligations. These trust fund
investments hold debt and equity securities directly and equity securities indirectly through commingled funds. The fair values
of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1.
In addition, U.S. government and federal agency obligations are categorized as Level 1 because they trade in a highly liquid and
transparent market. The fair values of corporate debt securities are based on evaluated prices that reflect observable market
information, such as actual trade information of similar securities, adjusted for observable differences and are categorized in
Level 2. Certain equity securities, classified as commingled funds, are analogous to mutual funds, are maintained by investment
companies, and hold certain investments in accordance with a stated set of fund objectives. The fair value of the equity securities
classified as commingled funds are based on net asset values per fund share (the unit of account), derived from the quoted prices
in active markets of the underlying equity securities. However, because the shares in the commingled funds are not publicly
quoted, not traded in an active market and are subject to certain restrictions regarding their purchase and sale, the commingled
funds are categorized in Level 3. See also Note 6, Nuclear Decommissioning Trust Fund.
(b) Transfers into/out of Level 3 are related to the availability of external broker quotes, and are valued as of the end of the reporting period. All transfers
into/out of Level 3 are from/to Level 2.
152
153
Derivative fair value measurements
A portion of the Company's contracts are exchange-traded contracts with readily available quoted market prices. A majority
of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations
available through brokers or over-the-counter and on-line exchanges. For the majority of NRG markets, the Company receives
quotes from multiple sources. To the extent that NRG receives multiple quotes, the Company's prices reflect the average of the
bid-ask mid-point prices obtained from all sources that NRG believes provide the most liquid market for the commodity. If the
Company receives one quote, then the mid-point of the bid-ask spread for that quote is used. The terms for which such price
information is available vary by commodity, region and product. A significant portion of the fair value of the Company's derivative
portfolio is based on price quotes from brokers in active markets who regularly facilitate those transactions and the Company
believes such price quotes are executable. The Company does not use third party sources that derive price based on proprietary
models or market surveys. The remainder of the assets and liabilities represents contracts for which external sources or observable
market quotes are not available. These contracts are valued based on various valuation techniques including but not limited to
internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar
characteristics. Contracts valued with prices provided by models and other valuation techniques make up 6% of derivative assets
and 10% of derivative liabilities. The fair value of each contract is discounted using a risk free interest rate. In addition, the
Company applies a credit reserve to reflect credit risk, which for interest rate swaps is calculated utilizing the bilateral method
based on published default probabilities. For commodities, to the extent that NRG's net exposure under a specific master agreement
is an asset, the Company uses the counterparty's default swap rate. If the exposure under a specific master agreement is a liability,
the Company uses NRG's default swap rate. For interest rate swaps and commodities, the credit reserve is added to the discounted
fair value to reflect the exit price that a market participant would be willing to receive to assume NRG's liabilities or that a market
participant would be willing to pay for NRG's assets. As of December 31, 2017, the credit reserve resulted in no change in fair
value in operating revenue and cost of operations. As of December 31, 2016 the credit reserve resulted in a $10 million decrease
in fair value in operating revenue and cost of operations.
The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2017, and may
change as a result of changes in these factors. Management uses its best estimates to determine the fair value of commodity and
derivative contracts NRG holds and sells. These estimates consider various factors including closing exchange and over-the-
counter price quotations, time value, volatility factors and credit exposure. It is possible, however, that future market prices could
vary from those used in recording assets and liabilities from energy marketing and trading activities and such variations could be
material.
NRG's significant positions classified as Level 3 include physical and financial power executed in illiquid markets as well
as financial transmission rights, or FTRs. The significant unobservable inputs used in developing fair value include illiquid power
location pricing which is derived as a basis to liquid locations. The basis spread is based on observable market data when available
or derived from historic prices and forward market prices from similar observable markets when not available. For FTRs, NRG
uses the most recent auction prices to derive the fair value.
The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level
3 positions as of December 31, 2017 and 2016:
Significant Unobservable Inputs
December 31, 2017
Fair Value
Input/Range
Power Contracts
FTRs
Assets
Liabilities
(In millions)
$
$
34
$
11
45
$
65
12
77
Valuation
Technique
Significant
Unobservable
Input
Low
High
Weighted
Average
Discounted
Cash Flow
Discounted
Cash Flow
Forward Market
Price (per MWh)
Auction Prices (per
MWh)
$
10
$
142
$
(28)
46
33
—
Significant Unobservable Inputs
December 31, 2016
Fair Value
Input/Range
Power Contracts
FTRs
Assets
Liabilities
(In millions)
$
$
39
$
51
90
$
108
50
158
Valuation
Technique
Significant
Unobservable
Input
Low
High
Weighted
Average
Discounted
Cash Flow
Discounted
Cash Flow
Forward Market
Price (per MWh)
Auction Prices (per
MWh)
$
11
$
104
$
(22)
17
31
—
The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable
inputs as of December 31, 2017 and 2016:
Significant Unobservable Input
Forward Market Price Power
Forward Market Price Power
FTR Prices
FTR Prices
Position
Buy
Sell
Buy
Sell
Change In Input
Increase/(Decrease)
Increase/(Decrease)
Increase/(Decrease)
Increase/(Decrease)
Impact on Fair Value
Measurement
Higher/(Lower)
Lower/(Higher)
Higher/(Lower)
Lower/(Higher)
Under the guidance of ASC 815, entities may choose to offset cash collateral posted or received against the fair value of
derivative positions executed with the same counterparties under the same master netting agreements. The Company has chosen
not to offset positions as defined in ASC 815. As of December 31, 2017, the Company recorded $171 million of cash collateral
posted and $37 million of cash collateral received on its balance sheet.
Concentration of Credit Risk
In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, the following
item is a discussion of the concentration of credit risk for the Company's financial instruments. Credit risk relates to the risk of
loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. The
Company monitors and manages credit risk through credit policies that include: (i) an established credit approval process; (ii) a
daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures such as margin, collateral, prepayment
arrangements, or volumetric limits; (iv) the use of payment netting agreements; and (v) the use of master netting agreements that
allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risks surrounding
counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks
to mitigate counterparty risk by having a diversified portfolio of counterparties. The Company also has credit protection within
various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at the Company
to cover the credit risk of the counterparty until positions settle.
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155
Counterparty Credit Risk
Retail Customer Credit Risk
As of December 31, 2017, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, and registered
commodity exchanges and certain long-term agreements, was $220 million and NRG held collateral (cash and letters of credit)
against those positions of $30 million, resulting in a net exposure of $196 million. Approximately 73% of the Company's exposure
before collateral is expected to roll off by the end of 2019. Counterparty credit exposure is valued through observable market
quotes and discounted at a risk free interest rate. The following tables highlight net counterparty credit exposure by industry sector
and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with
counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS,
and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.
Category
Financial institutions
Utilities, energy merchants, marketers and other
Total
Category
Investment grade
Non-Investment grade/Non-Rated
Total
Net Exposure (a) (b)
(% of Total)
14%
86
100%
Net Exposure (a) (b)
(% of Total)
69%
31
100%
(a) Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.
(b) The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long
term contracts.
NRG has counterparty credit risk exposure to certain counterparties, each of which represent more than 10% of total net
exposure discussed above. The aggregate of such counterparties' exposure was $37 million as of December 31, 2017. Changes
in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality,
diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company's financial
position or results of operations from nonperformance by any of NRG's counterparties.
RTOs and ISOs
The Company participates in the organized markets of CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM, known as RTOs
or ISOs. Trading in these markets is approved by FERC, or in the case of ERCOT, approved by the PUCT and includes credit
policies that, under certain circumstances, require that losses arising from the default of one member on spot market transactions
be shared by the remaining participants. As a result, the counterparty credit risk to these markets is limited to NRG’s share of
overall market and are excluded from the above exposures.
Exchange Traded Transactions
The Company enters into commodity transactions on registered exchanges, notably ICE and NYMEX. These clearinghouses
act as the counterparty and transactions are subject to extensive collateral and margining requirements. As a result, these commodity
transactions have limited counterparty credit risk.
Long Term Contracts
Counterparty credit exposure described above excludes credit risk exposure under certain long term agreements, including
California tolling agreements, Gulf Coast load obligations, wind and solar PPAs. As external sources or observable market quotes
are not available to estimate such exposure, the Company values these contracts based on various techniques including, but not
limited to, internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar
characteristics. Based on these valuation techniques, as of December 31, 2017, aggregate credit risk exposure managed by NRG
to these counterparties was approximately $4.1 billion, including $2.6 billion related to assets of NRG Yield, Inc., for the next
five years. This amount excludes potential credit exposures for projects with long term PPAs that have not reached commercial
operations. The majority of these power contracts are with utilities or public power entities with strong credit quality and public
utility commission or other regulatory support. However, such regulated utility counterparties can be impacted by changes in
government regulations, which NRG is unable to predict.
The Company is exposed to retail credit risk through the Company's retail electricity providers, which serve C&I customers
and the Mass market. Retail credit risk results in losses when a customer fails to pay for services rendered. The losses may result
from both nonpayment of customer accounts receivable and the loss of in-the-money forward value. The Company manages retail
credit risk through the use of established credit policies that include monitoring of the portfolio and the use of credit mitigation
measures such as deposits or prepayment arrangements.
As of December 31, 2017, the Company's retail customer credit exposure to C&I and Mass customers was diversified across
many customers and various industries, as well as government entities. The Company is also subject to risk with respect to its
residential solar customers. The Company's bad debt expense was $68 million, $48 million, and $64 million for the years ending
December 31, 2017, 2016, and 2015, respectively. Current economic conditions may affect the Company's customers' ability to
pay bills in a timely manner, which could increase customer delinquencies and may lead to an increase in bad debt expense.
Note 5 — Accounting for Derivative Instruments and Hedging Activities
ASC 815 requires the Company to recognize all derivative instruments on the balance sheet as either assets or liabilities and
to measure them at fair value each reporting period unless they qualify for a NPNS exception. The Company may elect to designate
certain derivatives as cash flow hedges, if certain conditions are met, and defer the change in fair value of the derivatives to
accumulated OCI, until the hedged transactions occur and are recognized in earnings.
For derivatives that are not designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes
in the fair value will be immediately recognized in earnings. Certain derivative instruments may qualify for the NPNS exception
and are therefore exempt from fair value accounting treatment. ASC 815 applies to NRG's energy related commodity contracts,
interest rate swaps, and equity contracts.
As the Company engages principally in the trading and marketing of its generation assets and retail businesses, some of
NRG's commercial activities qualify for hedge accounting. In order for the generation assets to qualify, the physical generation
and sale of electricity should be highly probable at inception of the trade and throughout the period it is held, as is the case with
the Company's baseload plants. For this reason, trades in support of NRG's baseload units may qualify for NPNS or cash flow
hedge accounting treatment, and trades in support of NRG's peaking units' asset optimization will generally not qualify for hedge
accounting treatment, with any changes in fair value likely to be reflected on a mark-to-market basis in the statement of operations.
Most of the retail load contracts either qualify for the NPNS exception or fail to meet the criteria for a derivative and the majority
of the retail supply and fuels supply contracts are recorded under mark-to-market accounting. All of NRG's hedging and trading
activities are subject to limits within the Company's Risk Management Policy.
Energy-Related Commodities
To manage the commodity price risk associated with the Company's competitive supply activities and the price risk associated
with wholesale power sales from the Company's electric generation facilities and retail power sales from NRG's retail businesses,
NRG enters into a variety of derivative and non-derivative hedging instruments, utilizing the following:
•
•
•
Forward contracts, which commit NRG to purchase or sell energy commodities or purchase fuels in the future;
Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial
instrument;
Swap agreements, which require payments to or from counterparties based upon the differential between two prices for
a predetermined contractual, or notional, quantity;
• Option contracts, which convey to the option holder the right but not the obligation to purchase or sell a commodity;
• Extendable swaps, which include a combination of swaps and options executed simultaneously for different periods. This
combination of instruments allows NRG to sell out-year volatility through call options in exchange for natural gas swaps
with fixed prices in excess of the market price for natural gas at that time. The above-market swap combined with its
later-year call option are priced in aggregate at market at the trade's inception; and
• Weather derivative products used to mitigate a portion of lost revenue due to weather.
The objectives for entering into derivative contracts designated as hedges include:
•
•
•
Fixing the price for a portion of anticipated future electricity sales that provides an acceptable return on the Company's
electric generation operations;
Fixing the price of a portion of anticipated fuel purchases for the operation of the Company's power plants; and
Fixing the price of a portion of anticipated power purchases for the Company's retail sales.
156
157
NRG's trading and hedging activities are subject to limits within the Company's Risk Management Policy. These contracts
are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized
in earnings.
As of December 31, 2017, NRG's derivative assets and liabilities consisted primarily of the following:
•
•
Forward and financial contracts for the purchase/sale of electricity and related products economically hedging NRG's
generation assets' forecasted output or NRG's retail load obligations through 2031;
Forward and financial contracts for the purchase of fuel commodities relating to the forecasted usage of NRG's generation
assets through 2019; and
• Other energy derivatives instruments extending through 2024.
Also, as of December 31, 2017, NRG had other energy-related contracts that did not meet the definition of a derivative
instrument or qualified for the NPNS exception and were therefore exempt from fair value accounting treatment as follows:
• Load-following forward electric sale contracts extending through 2026;
•
Power tolling contracts through 2043;
• Coal purchase contracts through 2021;
•
Power transmission contracts through 2025;
• Natural gas transportation contracts and storage agreements through 2030; and
• Coal transportation contracts through 2029.
Interest Rate Swaps
NRG is exposed to changes in interest rates through the Company's issuance of variable rate debt. In order to manage the
Company's interest rate risk, NRG enters into interest rate swap agreements. As of December 31, 2017, NRG had interest rate
derivative instruments on recourse debt extending through 2021 and non-recourse debt extending through 2041, some of which
are designated as cash flow hedges.
Volumetric Underlying Derivative Transactions
The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by
commodity, excluding those derivatives that qualified for the NPNS exception as of December 31, 2017 and 2016. Option contracts
are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option
will be in-the-money at its expiration date.
Commodity
Units
Short Ton
Short Ton
Emissions
Coal
Natural Gas MMBtu
Oil
Power
Capacity
Interest
Equity
Barrel
MWh
MW/Day
Dollars
Shares
Total Volume
December 31,
2017
December 31,
2016
(In millions)
1
21
(17)
—
14
(1)
3,876
1
$
—
35
(53)
1
7
(1)
3,429
1
$
Fair Value of Derivative Instruments
The following table summarizes the fair value within the derivative instrument valuation on the balance sheet:
(In millions)
Derivatives Designated as Cash Flow or Fair Value
Hedges:
Interest rate contracts current
Interest rate contracts long-term
Total Derivatives Designated as Cash Flow or Fair
Value Hedges
Derivatives Not Designated as Cash Flow or Fair
Value Hedges:
Interest rate contracts current
Interest rate contracts long-term
Commodity contracts current
Commodity contracts long-term
Total Derivatives Not Designated as Cash Flow or Fair
Value Hedges
Total Derivatives
$
$
Fair Value
Derivative Assets
Derivative Liabilities
December 31,
2017
December 31,
2016
December 31,
2017
December 31,
2016
1
11
12
9
32
616
129
786
798
$
— $
12
12
—
37
1,067
132
1,236
$
1,248
$
5
11
16
15
28
535
158
736
752
$
$
28
41
69
7
12
1,057
231
1,307
1,376
The Company has elected to present derivative assets and liabilities on the balance sheet on a trade-by-trade basis and
does not offset amounts at the counterparty master agreement level. In addition, collateral received or paid on the Company's
derivative assets or liabilities are recorded on a separate line item on the balance sheet. The following table summarizes the
offsetting derivatives by counterparty master agreement level and collateral received or paid:
Gross Amounts Not Offset in the Statement of Financial Position
Gross Amounts of
Recognized Assets/
Liabilities
Derivative
Instruments
Cash Collateral
(Held)/Posted
Net Amount
As of December 31, 2017
Commodity contracts:
Derivative assets
$
Derivative liabilities
Total commodity contracts
Interest rate contracts:
Derivative assets
Derivative liabilities
Total interest rate contracts
745
$
(693)
52
53
(59)
(6)
(In millions)
(578) $
578
—
(3)
3
—
Total derivative instruments
$
46
$
— $
(11) $
73
62
—
—
—
62
$
156
(42)
114
50
(56)
(6)
108
The decrease in the natural gas position was primarily the result of the settlement of generation hedge positions. The
increase in the interest rate position was primarily the result of entering into new interest rate swaps to hedge additional non-
recourse project level debt.
158
159
Gross Amounts Not Offset in the Statement of Financial Position
Gross Amounts of
Recognized Assets/
Liabilities
Derivative
Instruments
Cash Collateral
(Held)/Posted
Net Amount
As of December 31, 2016
Commodity contracts:
Derivative assets
$
1,199
$
Derivative liabilities
Total commodity contracts
Interest rate contracts:
Derivative assets
Derivative liabilities
Total interest rate contracts
(1,288)
(89)
49
(88)
(39)
(In millions)
(1,021) $
1,021
—
(4)
4
—
Total derivative instruments
$
(128) $
— $
Accumulated Other Comprehensive Income
(13) $
13
—
—
—
— $
165
(254)
(89)
45
(84)
(39)
(128)
The following tables summarize the effects on NRG's accumulated OCI balance attributable to cash flow hedge derivatives,
net of tax:
Accumulated OCI balance at December 31, 2016
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts
Mark-to-market of cash flow hedge accounting contracts
Accumulated OCI balance at December 31, 2017, net of $8 tax
Losses expected to be realized from other comprehensive loss during the next 12 months, net
of $2 tax
Accumulated OCI balance at December 31, 2015
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts
Mark-to-market of cash flow hedge accounting contracts
Accumulated OCI balance at December 31, 2016, net of $16 tax
$
$
$
$
$
Accumulated OCI balance at December 31, 2014
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts
Mark-to-market of cash flow hedge accounting contracts
Accumulated OCI balance at December 31, 2015, net of $16 tax
$
$
Year Ended December 31, 2015
Energy
Commodities
Interest
Rate
(In millions)
Total
(1) $
(67) $
1
—
— $
14
(48)
(101) $
Year Ended December 31, 2017
Interest
Rate
Total
(In millions)
(66) $
12
—
(54) $
(12) $
(66)
12
—
(54)
(12)
Year Ended December 31, 2016
Interest
Rate
Total
(In millions)
(101) $
21
14
(66) $
(101)
21
14
(66)
(68)
15
(48)
(101)
Amounts reclassified from accumulated OCI into income are recorded to operating revenue for commodity contracts and
interest expense for interest rate contracts.
Accounting guidelines require a high degree of correlation between the derivative and the hedged item throughout the
period in order to qualify as a cash flow hedge. As of December 31, 2016, the Company's regression analysis for Viento
Funding II interest rate swaps, while positively correlated, did not meet the required threshold for cash flow hedge accounting.
As a result, the Company de-designated the Viento Funding II cash flow hedges as of December 31, 2016, and will
prospectively mark these derivatives to market through the income statement.
The Company's regression analysis for Marsh Landing, Walnut Creek and Avra Valley interest rate swaps, while
positively correlated, no longer contain matching terms for cash flow hedge accounting. As a result, the Company voluntarily
de-designated the Marsh Landing, Walnut Creek and Avra Valley cash flow hedges as of April 28, 2017, and will prospectively
mark these derivatives to market through the income statement.
Impact of Derivative Instruments on the Statement of Operations
Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash
flow hedges are reflected in current period earnings.
The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges,
and trading activity on the Company's statement of operations. The effect of commodity hedges is included within operating
revenues and cost of operations and the effect of interest rate hedges is included in interest expense.
Unrealized mark-to-market results
Reversal of previously recognized unrealized loss/(gains) on settled
positions related to economic hedges
Reversal of acquired gain positions related to economic hedges
Net unrealized gains/(losses) on open positions related to economic
hedges
Total unrealized mark-to-market gains/(losses) for economic hedging
activities
Reversal of previously recognized unrealized (gains)/losses on settled
positions related to trading activity
Reversal of acquired gain positions related to trading activity
Net unrealized gains/(losses) on open positions related to trading activity
Total unrealized mark-to-market (losses)/gains for trading activity
Total unrealized gains/(losses)
Unrealized gains/(losses) included in operating revenues
Unrealized (losses)/gains included in cost of operations
Total impact to statement of operations — energy commodities
Total impact to statement of operations — interest rate contracts
Year Ended December 31,
2017
2016
(In millions)
2015
$
$
$
$
$
$
47
—
(128) $
(12)
146
193
(25)
—
14
(11)
182
6
(134)
10
—
18
28
(106) $
$
Year Ended December 31,
2017
2016
(In millions)
2015
228
(46)
182
9
$
$
$
(614) $
508
(106) $
$
36
(162)
(22)
(9)
(193)
(46)
(14)
(16)
(76)
(269)
(210)
(59)
(269)
17
The reversal of gain or loss positions acquired as part of acquisitions were valued based upon the forward prices on the
acquisition dates. The roll-off amounts were offset by realized gains or losses at the settled prices and are reflected in revenue or
cost of operations during the same period.
For the year ended December 31, 2017, the $146 million gain from economic hedge positions was primarily the result of an
increase in the value of forward purchases of ERCOT heat rate contracts due to ERCOT heat rate expansion.
For the year ended December 31, 2016, the $6 million gain from economic hedge positions was primarily the result of an
increase in the value of forward purchases of natural gas due to an increase in natural gas prices.
160
161
For the year ended December 31, 2015, the $9 million loss from economic hedge positions was primarily the result of a
The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses
decrease in the value of forward purchases of natural gas due to a decrease in natural gas prices.
from these sales. The cost of securities sold is determined using the specific identification method.
Credit Risk Related Contingent Features
Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if
the counterparty determines that there has been deterioration in credit quality, generally termed "adequate assurance" under the
agreements, or require the Company to post additional collateral if there were a one notch downgrade in the Company's credit
rating. The collateral required for contracts that have adequate assurance clauses that are in net liability positions as of December 31,
2017 was $25 million. The collateral required for contracts with credit rating contingent features that are in a net liability position
as of December 31, 2017 was $7 million. The Company is also a party to certain marginable agreements under which it has a net
liability position, but the counterparty has not called for the collateral due, which was approximately $4 million as of December 31,
2017.
See Note 4, Fair Value of Financial Instruments, for discussion regarding concentration of credit risk.
Note 6 — Nuclear Decommissioning Trust Fund
NRG's Nuclear Decommissioning Trust Fund assets, which are for the decommissioning of STP, are comprised of securities
classified as available-for-sale and recorded at fair value based on actively quoted market prices. Although NRG is responsible
for managing the decommissioning of its 44% interest in STP, the predecessor utilities that owned STP are authorized by the PUCT
to collect decommissioning funds from their ratepayers to cover decommissioning costs on behalf of NRG. NRC requirements
determine the decommissioning cost estimate which is the minimum required level of funding. In the event that funds from the
ratepayers that accumulate in the nuclear decommissioning trust are ultimately determined to be inadequate to decommission the
STP facilities, the utilities will be required to collect through rates charged to rate payers all additional amounts, with no obligation
from NRG, provided that NRG has complied with PUCT rules and regulations regarding decommissioning trusts. Following
completion of the decommissioning, if surplus funds remain in the decommissioning trusts, any excess will be refunded to the
respective ratepayers of the utilities.
NRG accounts for the Nuclear Decommissioning Trust Fund in accordance with ASC 980, Regulated Operations, or ASC
980, because the Company's nuclear decommissioning activities are subject to approval by the PUCT, with regulated rates that
are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate.
Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of
decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including
other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to the Nuclear
Decommissioning Trust liability and are not included in net income or accumulated other comprehensive income, consistent with
regulatory treatment.
The following table summarizes the aggregate fair values and unrealized gains and losses (including other-than-temporary
impairments) for the securities held in the trust funds, as well as information about the contractual maturities of those securities.
Realized gains
Realized losses
Proceeds from sale of securities
Note 7 — Inventory
Inventory consisted of:
Fuel oil
Coal/Lignite
Natural gas
Spare parts
Total Inventory
Year Ended December 31,
2017
2016
(In millions)
2015
$
$
22
8
501
$
26
11
510
As of December 31,
2017
2016
(In millions)
$
$
90
126
24
292
532
$
$
21
14
631
142
219
28
332
721
During the year ended December 31, 2017, the Company recorded a lower of weighted average cost or market adjustment
related to fuel oil of $33 million.
Note 8 — Notes Receivable
Notes receivable consist of fixed and variable rate notes related primarily to amounts owed to the Company from transmission
owners for certain projects for the financing of network upgrades. The Company's notes receivable were as follows:
Notes receivable
Less current maturities(a)
Total notes receivable — non-current
As of December 31,
2017
2016
(In millions)
$
$
16
14
2
$
$
34
18
16
(a) The current portion of notes receivable is recorded in prepayments and other current assets on the consolidated balance sheets.
As of December 31, 2017
As of December 31, 2016
Note 9 — Property, Plant and Equipment
(In millions, except otherwise noted)
Fair
Value
Unrealized
Gains
Unrealized
Losses
Cash and cash equivalents
$
47
$
— $
U.S. government and federal agency
obligations
Federal agency mortgage-backed
securities
Commercial mortgage-backed securities
Corporate debt securities
Equity securities
Foreign government fixed income
securities
Total
43
82
13
99
403
5
1
1
—
2
272
—
$
692
$
276
$
—
—
1
—
1
—
—
2
Weighted-
average
maturities
(in years)
Fair
Value
Unrealized
Gains
Unrealized
Losses
Weighted-
average
maturities
(in years)
— $
25
$
— $
11
23
20
11
—
9
73
62
17
84
346
3
1
1
—
1
214
—
$
610
$
217
$
—
—
1
1
2
—
—
4
—
11
25
26
11
—
9
The Company's major classes of property, plant, and equipment were as follows:
Facilities and equipment
Land and improvements
Nuclear fuel
Office furnishings and equipment
Construction in progress
Total property, plant, and equipment
Accumulated depreciation
Net property, plant, and equipment
Depreciable
Lives
1-40 Years
5 Years
2-10 Years
As of December 31,
2017
2016
(In millions)
$
$
15,907
710
236
434
1,086
18,373
(4,465)
13,908
$
$
18,698
750
226
412
619
20,705
(5,336)
15,369
162
163
The Company recorded long-lived asset impairments during the years ended December 31, 2017 and 2016, as further
described in Note 10, Asset Impairments.
Note 10 — Asset Impairments
2017 Impairment Losses
During the fourth quarter of 2017, the Company completed its annual budget and revised its view of long-term power and
fuel prices and the corresponding impact on estimated cash flows associated with its long-lived assets. The most significant impact
was a decrease in the Company's long-term view of natural gas prices which resulted in a reduction to long-term power prices and
had a negative impact on the Company's coal, nuclear and renewable facilities. Each of the facilities below had estimated cash
flows that were lower than the carrying amount and the assets were considered impaired.
The fair values of the assets were determined using an income approach by applying a discounted cash flow methodology to
the long-term budget for the facility. The income approach utilized estimates of discounted future cash flows, which were Level
3 fair value measurements, an include key inputs such as forecasted power prices, nuclear fuel costs, forecasted operating and
maintenance costs, plant investment capital expenditures and discount rates.
South Texas Project, or STP — The Company recognized an impairment loss of $1,248 million related to its interest in STP
as a result of the decrease in the Company's view of long-term power prices in ERCOT.
Indian River — The Company recognized an impairment loss of $36 million for Indian River as a result of the decrease in
the Company's view of long-term power prices in PJM.
Keystone and Conemaugh — The Company recognized impairment losses of $35 million for Keystone and $35 million for
Conemaugh as a result of the decrease in the Company's view of long-term power prices in PJM.
Wind Facilities — The Company recorded impairment losses of $110 million, $26 million and $4 million for Langford,
Elbow Creek and Forward, respectively, as a result of the decrease in the Company's view of long-term merchant power prices
in ERCOT and PJM. While Elbow Creek and Forward have contracts to sell power, the significant decrease in estimated power
prices had an impact on cash flows in post-contract periods.
The Company also recorded the following impairments in 2017 based on specific triggering events that occurred:
Bacliff Project — On June 16, 2017, NRG Texas Power LLC provided notice to BTEC New Albany, LLC that it was
exercising its right to terminate the Amended and Restated Membership Interest Purchase Agreement, or MIPA, due to the Bacliff
Project, a new peaking facility at the former P.H. Robinson Electric Generating Station, not achieving commercial completion
by the contractual expiration date of May 31, 2017. As a result of the MIPA termination, the Company recorded an impairment
loss of $41 million to reduce the carrying amount of the related construction in progress to zero during the second quarter of
2017. On July 14, 2017, the Company gave notice to BTEC New Albany, LLC that it owes NRG Texas Power LLC approximately
$48 million under the terminated MIPA, consisting of $38 million in purchaser incurred costs and $10 million in liquidated
damages.
Other Long-Lived Asset Impairments — During the second, third and fourth quarters of 2017, the Company recorded
impairment losses of approximately $22 million, $14 million and $15 million, respectively, in connection with the Company's
Renewables business. These impairment losses were primarily to record the value of certain long-lived assets, including property,
plant and equipment and intangible assets, at fair market value at acquisition date or in connection with an impairment indicator.
Petra Nova Parish Holdings — In connection with the preparation of the annual budget during the fourth quarter,
management revised its view of oil production expectations with respect to Petra Nova Parish Holdings. As a result, the Company
reviewed its 50% interest in Petra Nova Parish Holdings for impairment utilizing the other-than-temporary impairment model.
In determining fair value, the Company utilized an income approach and considered project specific assumptions for the future
project cash flows. The carrying amount of the Company's equity method investment exceeded the fair value of the investment
and the Company concluded that the decline is considered to be other-than-temporary. As a result, the Company measured the
impairment loss as the difference between the carrying amount and the fair value of the investment and recorded an impairment
loss of $69 million.
The Company also recorded an additional $11 million in impairment losses for other investments during the fourth quarter
of 2017.
2016 Impairment Losses
Rockford — As described in Note 3, Discontinued Operations, Acquisitions and Dispositions, on May 12, 2016, the Company
entered into an agreement with RA Generation, LLC to sell 100% of its interests in the Rockford generating stations for cash
consideration of $55 million. The transaction triggered an indicator of impairment as the sale price was less than the carrying
amount of the assets, and, as a result, the assets were considered to be impaired. The Company measured the impairment loss as
the difference between the carrying amount of the assets and the agreed-upon sale price. The Company recorded an impairment
loss of $17 million during the year ended December 31, 2016, to reduce the carrying amount of the assets held for sale to the fair
market value.
Wind Facilities — During the fourth quarter of 2016, as the Company updated its estimated future cash flows in connection
with the preparation of its annual budget, the Company determined that the cash flows for the Elbow Creek and Goat Wind projects,
located in Texas and the Forward project, located in Pennsylvania were below the carrying value of the related assets, primarily
driven by the declining merchant power prices in post-contract periods, and the assets were considered impaired. The fair values
of the facilities were determined using an income approach by applying a discounted cash flow methodology to the long-term
budgets for each respective plant. The income approach utilized estimates of discounted future cash flows, which were Level 3
fair value measurements and include key inputs, such as forecasted power prices, operations and maintenance expense and discount
rates. The Company measured the impairment loss as the difference between the carrying amount and the fair value of the assets
and recorded impairment losses of $117 million, $60 million and $6 million for Elbow Creek, Goat Wind and Forward, respectively.
Long Beach — During the fourth quarter of 2016, the Company determined that by the end of 2017 it would retire its Long
Beach generation station located in Long Beach, California. The generating station was not awarded a PPA extension in SCE's
capacity auction during the fourth quarter of 2016 for the PPA set to expire on July 31, 2017. The Company considered this to be
an indicator of impairment and performed an impairment test. The Company measured the impairment loss as the difference
between the carrying amount and the fair value of the assets and recorded an impairment loss of $36 million. Subsequently,
management decided to continue to operate in 2018, which did not significantly impact fair value.
Other Impairments — During 2016, the Company recorded other impairment losses of $153 million, which included $23
million in excess SO2 allowances, $23 million for other intangible assets, $19 million in previously purchased solar panels, $18
million in deferred marketing expenses, $22 million in other investments and $48 million of other impairment losses.
Petra Nova Parish Holdings — During the first quarter of 2016, management changed its plans with respect to its future
capital commitments driven in part by the continued decline in oil prices. As a result, the Company reviewed its 50% interest in
Petra Nova Parish Holdings for impairment utilizing the other-than-temporary impairment model. In determining fair value, the
Company utilized an income approach and considered project specific assumptions for the future project cash flows. The carrying
amount of the Company's equity method investment exceeded the fair value of the investment and the Company concluded that
the decline is considered to be other-than-temporary. As a result, the Company measured the impairment loss as the difference
between the carrying amount and the fair value of the investment and recorded an impairment loss of $140 million.
Community Wind North and Sherbino — During the fourth quarter of 2016, the Company offered several projects to NRG
Yield including its interest in Community Wind North. The offer price was below its current carrying amount and this decline in
fair value was determined to be other-than-temporary. Accordingly, the Company recorded an impairment loss of $36 million to
reduce its carrying amount to fair value. In addition, in connection with the preparation of the annual budget, the Company noted
that due to the anticipated difficulty in refinancing Sherbino’s debt that will mature in 2018, the project’s fair value had decreased
significantly below its carrying amount and this decline was determined to be other-than-temporary. Accordingly, the Company
determined that an other-than-temporary impairment existed and recorded an impairment loss on its investment in Sherbino of
$70 million.
2015 Impairment Losses
Limestone and W.A. Parish — During the fourth quarter of 2015, as the Company updated its estimates of future cash flows
in connection with the preparation of its annual budget, it was noted that the cash flows for the Limestone and W.A. Parish coal-
fired facilities located in Texas were lower than the carrying amount, primarily driven by declining power prices as the cost of
commodities continues to decline and the assets were impaired. The fair value of the Limestone and W.A. Parish plants was
determined using an income approach by applying a discounted cash flow methodology to the long-term budgets for each respective
plant. The income approach utilized estimates of discounted future cash flows, which were Level 3 fair value measurements, and
include key inputs such as forecasted power prices, fuel costs and emissions credit expense, forecasted operating and capital
expenditures and discount rates. The Company measured the impairment loss as the difference between the carrying amount and
the fair value of the assets and recognized impairment losses of $1,514 million and $1,295 million related to Limestone and W.A.
Parish, respectively.
164
165
Huntley — On August 25, 2015, the Company filed a notice with the NYSPSC of its intent to retire Huntley's operating units
on March 1, 2016. The Company considered this to be an indicator of impairment and performed an impairment test for these
assets under ASC 360, Property, Plant and Equipment. On October 14, 2015, the Company filed a cost-of-service filing at FERC
in anticipation that the Huntley operating units would be needed for reliability purposes, proposing a reliability must run service
agreement for a four-year period beginning on March 1, 2016. On October 30, 2015, NYISO released the results of its reliability
study, indicating that the Huntley operating units are not needed for bulk system reliability. The Company considered the impact
of the reliability study conducted and evaluated the estimated cash flows associated with the facility. Accordingly, the Company
determined that the carrying amount of the assets was higher than the estimated future net cash flows expected to be generated
by the assets and that the assets were impaired. The fair value of the Huntley operating units was determined using the income
approach. The income approach utilized estimates of discounted future cash flows, which were Level 3 fair value measurements,
and include key inputs such as forecasted contract prices, forecasted operating expenses and discount rates. The Company recorded
an impairment loss of $132 million during the year ended December 31, 2015.
Dunkirk — The Company signed a ten-year agreement in November 2014 with National Grid to add natural gas-burning
capabilities at the Dunkirk facility. On August 25, 2015, NRG announced that Dunkirk Unit 2 would be mothballed on January
1, 2016 at the expiration of its reliability support services agreement. The project to add natural gas-burning capabilities has been
suspended, pending the outcome of litigation with respect to the gas addition contract and its validity. On October 30, 2015,
NYISO released the results of its reliability study, indicating that the Dunkirk facility is not needed for system reliability. In
connection with the planned mothball of the facility, the pending litigation and the latest reliability assessment completed by
NYISO, the Company evaluated whether the related fixed assets were impaired. The Company determined that the carrying amount
of the assets was higher than the estimated future net cash flows expected to be generated by the assets and that the assets were
impaired. The fair value of the Dunkirk facility was determined using the income approach. The income approach utilized estimates
of discounted future cash flows, which were Level 3 fair value measurements, and include key inputs such as forecasted contract
prices, forecasted operating and capital expenditures and discount rates. The Company recorded an impairment loss of $160 million
during the year ended December 31, 2015.
Gregory — During the fourth quarter of 2015, the Company determined that the carrying amount of the assets was higher
than the estimated future net cash flows expected to be generated by the assets and that the assets were impaired. The fair value
of the Gregory facility was determined using the income approach, which utilized estimates of discounted future cash flows, which
were Level 3 fair value measurements, and include key inputs such as forecasted prices, operating and capital expenditures and
discount rates. The Company recorded an impairment loss of $176 million during the year ended December 31, 2015.
Solar Panels — During the fourth quarter of 2015, the Company recorded an impairment loss of $29 million to reduce the
carrying value of certain solar panels to their approximate fair value.
Investments — During the fourth quarter of 2015, the Company reviewed certain of its cost method and equity method
investments and concluded that losses incurred by these investments were other-than-temporary. These losses were primarily
driven by the sustained decline in stock price of a publicly traded investment as well as change in financing structures of certain
non-publicly traded investments. As a result, the Company recorded losses related to these investments of $56 million.
Note 11 — Goodwill and Other Intangibles
Goodwill
NRG's goodwill balance was $539 million and $662 million as of December 31, 2017 and 2016, respectively. As of
December 31, 2017, and 2016, NRG had approximately $460 million and $547 million, respectively, of goodwill that is deductible
for U.S. income tax purposes in future periods. As of December 31, 2017, goodwill consisted of $165 million associated with the
acquisition of EME, $341 million for Retail business acquisitions, and $33 million associated with other business acquisitions.
2017 Impairments of Goodwill
BETM — During the fourth quarter of 2017, the Company concluded that BETM was held for sale in connection with board
approval and advanced negotiations to sell the business. Accordingly, the Company recorded the assets and liabilities at fair market
value as of December 31, 2017, which resulted in an impairment loss of $90 million to record BETM’s goodwill at fair market value.
The remaining goodwill balance for BETM of $21 million is included within non-current assets held-for-sale as of December 31,
2017.
SPP — During the fourth quarter of 2017, NRG sold its interests in certain SPP projects to NRG Yield. The goodwill
recorded during the SPP acquisition was related primarily to its development pipeline, which was not sold to NRG Yield. As the
Company does not expect to separately develop these projects and accordingly, has no cash flow stream associated with the goodwill,
an impairment loss of $12 million was recorded to reduce the value to zero as of December 31, 2017.
2016 Impairments of Goodwill
During the year ended December 31, 2016, the Company recorded a goodwill impairment charge of $337 million related
to its Texas reporting unit, reducing the goodwill balance for Texas to zero.
In connection with the annual impairment assessment, the Company performed step one of the two-step impairment test
for the Texas reporting unit, for which $1.7 billion of goodwill was recognized as part of the Texas Genco acquisition in 2006 and
$1.4 billion was written off in 2015. The Company determined the fair value of the Texas reporting unit primarily using an income
approach through which the Company applied a discounted cash flow methodology to the long-term budgets for all plants in the
regions. Significant inputs impacting the income approach include the Company's views of power and fuel prices for the first five-
year period and the Company's view for the longer term, which were finalized in connection with the preparation of the fourth quarter
financial statements, projected generation based on an hourly dispatch meant to simulate the dispatch of each unit into the power
market which is impacted by power prices, fuel prices, and the physical and economic characteristics of each plant, intangible value
to Texas for synergies it provides to NRG's retail businesses, and the discount rate applied to cash flow projections. Under step one,
the estimated fair value of the Texas invested capital was 43% below its carrying value as of December 31, 2016, and the Company
concluded step two was required. Based on the results of step two of the impairment test, the Company determined the carrying
amount of the reporting unit was higher than the fair value, and accordingly, the Company recognized an impairment loss of $337
million as of December 31, 2016.
Intangible Assets
The Company's intangible assets as of December 31, 2017, primarily reflect intangible assets established with the acquisitions
of various companies and are comprised of the following:
• Emission Allowances — These intangibles primarily consist of SO2 and NOx emission allowances established with the 2006
Texas Genco acquisition and also include RGGI emission credits which NRG began purchasing in 2009. These emission
allowances are held-for-use and are amortized to cost of operations, with NOx allowances amortized on a straight-line basis
and SO2 allowances and RGGI credits amortized based on units of production. During the year ended December 31, 2017,
the Company recorded an impairment loss of $20 million to reduce the value of excess SO2 allowances to zero.
• Energy supply contracts — Established with the acquisitions of Reliant Energy and Green Mountain Energy, these represent
the fair value at the acquisition date of in-market contracts for the purchase of energy to serve retail electric customers. The
contracts are amortized to cost of operations based on the expected delivery under the respective contracts.
•
In-market fuel (gas and nuclear) contracts — These intangibles were established with the Texas Genco acquisition in 2006
and are amortized to cost of operations over expected volumes over the life of each contract.
• Customer contracts — Established with the acquisitions of Reliant Energy, Green Mountain Energy, and Northwind Phoenix,
these intangibles represent the fair value at the acquisition date of contracts that primarily provide electricity to Reliant
Energy's and Green Mountain Energy's C&I customers. These contracts are amortized to revenues based on expected
volumes to be delivered for the portfolio.
• Customer relationships — These intangibles represent the fair value at the acquisition date of acquired businesses' customer
base, primarily for Dominion, Energy Alternatives, Energy Plus, Reliant Energy, Green Mountain Energy, Energy Systems,
Energy Curtailment Specialists, and Source Power & Gas. The customer relationships are amortized to depreciation and
amortization expense based on the expected discounted future net cash flows by year.
• Marketing partnerships — Established with the acquisition of Energy Plus, these intangibles represent the fair value at the
acquisition date of existing agreements with loyalty and affinity partners. The marketing partnerships are amortized to
depreciation and amortization expense based on the expected discounted future net cash flows by year.
•
Trade names — Established with the Reliant Energy, Green Mountain, Energy Plus and Dominion acquisitions, these
intangibles are amortized to depreciation and amortization expense, on a straight-line basis.
• Power purchase agreements — Established predominantly with the EME and Alta Wind acquisitions, these represent the
fair value of PPAs acquired. These will be amortized to revenues, generally on a straight-line basis, over the terms of the
PPAs. During the year ended December 31, 2017, the Company recorded an impairment loss of $6 million related to PPAs.
• Other — Consists of renewable energy credits, wind leasehold rights, costs to extend the operating license for STP Units
1 and 2, and the intangible assets related to purchased ground leases.
166
167
The following tables summarize the components of NRG's intangible assets subject to amortization:
The following table presents NRG's amortization of intangible assets for each of the past three years:
Year Ended December 31,
2017
Emission
Allowances
Energy
Supply
Fuel Customer
Customer
Relationships
Marketing
Partnerships
Trade
Names
PPA
Other
Total
Amortization
Contracts
January 1, 2017
Purchases
Acquisition of
businesses
Usage
Write-off of fully
amortized balances(a)
Impairment
Other
December 31, 2017
Less accumulated
amortization
$
789
31
—
(10)
—
(20)
(23)
767
$
$72
54
— —
$
— —
— —
(54)
(23)
— —
— —
— 49
16
—
—
—
—
—
—
16
(591)
— (45)
(9)
Net carrying amount
$
176
$ — $ 4
$
7
$
$
(In millions)
816
—
$
18
—
—
—
—
834
88
—
—
—
—
—
—
88
$
342
—
$ 1,286
—
$198
32
$ 3,661
63
—
—
—
—
—
342
—
—
— (28)
18
(38)
—
—
(6) —
(19)
5
183
1,285
(77)
(26)
(37)
3,564
Emission allowances
Energy supply contracts
Fuel contracts
Customer contracts
Customer relationships
Marketing partnerships
Trade names
Power purchase agreements
Other
Total amortization
Years Ended December 31,
2017
2016
(In millions)
2015
$
73
—
1
1
35
5
23
62
7
$
66
$
7
2
2
49
8
22
64
11
60
5
2
2
67
14
23
51
14
$
207
$
231
$
238
(a) Adjusted for write-off of fully amortized energy supply contracts of $54 million and fuel contracts of $23 million.
Contracts
Contracts
Year Ended December 31,
Emission
Allowances
Fuel
Customer
Customer
Relationships
Marketing
Partnerships
Trade
Names
PPA
Other
Total
Year Ended December 31,
2016
Emission
Allowances
Energy
Supply
Fuel Customer
Customer
Relationships
Marketing
Partnerships
Trade
Names
PPA
Other
Total
(698)
136
$
(54)
34
$
(182)
160
(205)
$ 1,080
(34)
$149
(1,818)
$ 1,746
The following table presents estimated amortization of NRG's intangible assets for each of the next five years:
January 1, 2016
$
816
$
54
$72
$
Purchases
Acquisition of
businesses
Usage
Write-off of fully
amortized balances(a)
Impairment(b)
Other
December 31, 2016
Less accumulated
amortization
13
—
(1)
(10)
(23)
(6)
789
— —
— —
— —
— —
— —
— —
54
72
(In millions)
$
834
$
—
—
—
—
(18)
—
816
16
—
—
—
—
—
—
16
88
—
—
—
—
—
—
88
$
342
$ 1,286
$213
$ 3,721
—
—
—
—
—
—
—
34
18
— (44)
—
—
— (23)
—
—
47
18
(45)
(10)
(64)
(6)
342
1,286
198
3,661
Net carrying amount
$
271
$ — $ 5
$
8
$
(518)
(54)
(67)
(8)
(663)
153
$
(49)
39
$
(159)
183
(143)
$ 1,143
(27)
$171
(1,688)
$ 1,973
(a) Adjusted for write-off of fully amortized emission allowances of $10 million.
(b) The impairment of customer relationships and other intangibles included a write-off of accumulated amortization of $10 million and $8 million, respectively.
2018
2019
2020
2021
2022
$
33
$ 1
$
30 —
16 —
16 —
15 —
$
1
1
1
1
1
(In millions)
$
25
21
17
13
7
$
5
4
4
4
3
$
22
22
22
22
22
$
64
64
64
64
64
8
8
8
8
8
$ 159
150
132
128
120
Intangible assets held for sale — From time to time, management may authorize the transfer from the Company's emission
bank of emission allowances held-for-use to intangible assets held-for-sale. Emission allowances held-for-sale are included in other
non-current assets on the Company's consolidated balance sheet and are not amortized, but rather expensed as sold. As of December 31,
2017, the value of emission allowances held-for-sale is $9 million and is managed within the Corporate segment. Once transferred
to held-for-sale, these emission allowances are prohibited from moving back to held-for-use.
Out-of-market contracts — Due primarily to business acquisitions, NRG acquired certain out-of-market contracts, which are
classified as non-current liabilities on NRG's consolidated balance sheet. These include out-of-market lease contracts of $159 million
acquired in the acquisition of EME. These out-of-market contracts are amortized to cost of operations. As of December 31, 2017
and 2016, the Company had accumulated amortization for out-of-market contracts of $358 million and $457 million, respectively.
The following table summarizes the estimated amortization related to NRG's out-of-market contracts:
Year Ended December 31,
Power Contracts
Leases
Total
2018
2019
2020
2021
2022
$
16
16
17
14
1
(In millions
$
$
9
9
9
9
9
25
25
26
23
10
168
169
December 31,
2017
2016
December 31, 2017
Interest Rate % (a)
Note 12 — Debt and Capital Leases
Long-term debt and capital leases consisted of the following:
(In millions, except rates)
Recourse debt:
Senior notes, due 2018
Senior notes, due 2021
Senior notes, due 2022
Senior notes, due 2023
Senior notes, due 2024
Senior notes, due 2026
Senior notes, due 2027
Senior notes, due 2028
Term loan facility, due 2023
Tax-exempt bonds
Subtotal recourse debt
Non-recourse debt:
$
— $
—
992
—
733
1,000
1,250
870
1,872
465
7,182
NRG Yield Operating LLC Senior Notes, due 2024
NRG Yield Operating LLC Senior Notes, due 2026
NRG Yield, Inc. Convertible Senior Notes, due 2019
NRG Yield, Inc. Convertible Senior Notes, due 2020
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due
2019 (b)
El Segundo Energy Center, due 2023
Marsh Landing, due 2023
Alta Wind I - V lease financing arrangements, due 2034 and 2035
Walnut Creek, term loans due 2023
Utah Portfolio, due 2022
Tapestry, due 2021
CVSR, due 2037
CVSR HoldCo, due 2037
Alpine, due 2022
Energy Center Minneapolis, due 2025
Energy Center Minneapolis, due 2031
Viento, due 2023
NRG Yield - other
Subtotal NRG Yield debt (non-recourse to NRG) (c)
Ivanpah, due 2033 and 2038
Carlsbad Energy Project (c)
Agua Caliente, due 2037
Agua Caliente Borrower 1, due 2038
Cedro Hill, due 2029 (c)
Midwest Generation, due 2019
NRG Other Renewables (c)
NRG Other
Subtotal other non-recourse debt
Subtotal all non-recourse debt
Subtotal long-term debt (including current maturities)
Capital leases
Subtotal long-term debt and capital leases (including current maturities)
Less current maturities
Less debt issuance costs
Discounts
Total long-term debt and capital leases
$
500
350
345
288
55
400
318
926
267
278
162
746
194
135
83
125
163
579
5,914
1,073
427
818
89
151
152
647
180
3,537
9,451
16,633
5
16,638
(688)
(204)
(30)
15,716
$
7.625
7.875
6.250
6.625
6.250
7.250
6.625
5.750
L+2.25
4.125 - 6.00
5.375
5.000
3.500
3.250
L+2.500
L+1.75 - L+2.375
L+1.875
5.696 - 7.015
L+1.625
L+2.625
L+1.625
2.339 - 3.775
4.680
L+1.750
3.55 - 5.95
3.55
L+3.00
various
2.285 - 4.256
L+1.625 -.04120
2.395 - 3.633
5.430
L+1.75
4.390
various
various
398
207
992
869
733
1,000
1,250
—
1,891
455
7,795
500
350
345
288
—
443
370
965
310
287
172
771
199
145
96
125
178
603
6,147
1,113
—
849
—
163
231
269
137
2,762
8,909
16,704
6
16,710
(516)
(188)
(49)
15,957
Long-term debt includes the following discounts:
Term loan facility, due 2023 (a)
Yield, Inc. Convertible notes, due 2019
Yield, Inc. Convertible notes, due 2020
Midwest Generation, due 2019
Total discounts
As of December 31,
2017
2016
(In millions)
(7) $
(5)
(13)
(5)
(30) $
(9)
(10)
(17)
(13)
(49)
$
$
(a) Term loan facility, due 2018 replaced with the Term loan facility due 2023. Discount of $1 million was related to current maturities in 2016.
Consolidated Annual Maturities
Annual payments based on the maturities of NRG's debt and capital leases for the years ending after December 31, 2017
are as follows:
2018
2019
2020
2021
2022
Thereafter
Total
Recourse Debt
Senior Notes
(In millions)
695
933
805
606
1,854
11,745
16,638
$
$
Issuance of 2028 Senior Notes
On December 7, 2017, NRG issued $870 million of aggregate principal amount at par of 5.75% senior unsecured notes due
2028. The 2028 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest
is paid semi-annually beginning on July 15, 2018, until the maturity date of January 15, 2028. The proceeds from the issuance
of the 2028 Senior Notes were utilized to redeem the Company's 6.625% Senior Notes due 2023.
Issuance of 2026 Senior Notes
On May 23, 2016, NRG issued $1.0 billion in aggregate principal amount at par of 7.25% senior notes due 2026, or the
2026 Senior Notes. The 2026 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its
subsidiaries. Interest is paid semi-annually beginning on November 15, 2016, until the maturity date of May 15, 2026. The
proceeds from the issuance of the 2026 Senior Notes were utilized to repurchase a portion of the Senior Notes during 2016.
Issuance of 2027 Senior Notes
On August 2, 2016, NRG issued $1.25 billion in aggregate principal amount at par of 6.625% senior notes due 2027, or the
2027 Senior Notes. The 2027 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its
subsidiaries. Interest is paid semi-annually beginning on January 15, 2017, until the maturity date of January 15, 2027. The
proceeds from the issuance of the 2027 Senior Notes were utilized to retire the Company's 8.250% senior notes due 2020 and
reduce the balance of the Company's 7.875% senior notes due 2021.
(a) As of December 31, 2017, L+ equals 3 month LIBOR plus x%, except for the Utah Solar Portfolio where L+ equals 1 month LIBOR plus 2.629%.
(b) Applicable rate is determined by the Borrower Leverage Ratio, as defined in the credit agreement
(c) Debt associated with the asset sales announced in February 2018
170
171
2017 Senior Note Redemptions
The Company periodically enters into supplemental indentures for the purpose of adding entities under the Senior Notes
During the year ended December 31, 2017, the Company redeemed $1.5 billion in aggregate principal of its Senior Notes
for $1.5 billion, which included accrued interest of $29 million. In connection with the redemptions, a $49 million loss on debt
extinguishment was recorded, which included the write-off of previously deferred financing costs of $7 million.
Amount in millions, except rates
7.625% senior notes due 2018
7.875% senior notes due 2021
6.625% senior notes due 2023
Total
(a) Includes payment for accrued interest.
2016 Senior Notes Repurchases
Principal
Repurchased
Cash Paid (a)
Average Early Redemption
Percentage
$
$
398
206
869
1,473
$
$
411
218
915
1,544
101.42%
102.63%
103.57%
During the year ended December 31, 2016, the Company repurchased $3.0 billion in aggregate principal of its Senior Notes
for $3.1 billion, which included accrued interest of $77 million. In connection with the repurchases, a $117 million loss on debt
extinguishment was recorded, which included the write-off of previously deferred financing costs of $16 million.
Amount in millions, except rates
7.625% senior notes due 2018 (b)
8.250% senior notes due 2020
7.875% senior notes due 2021 (c)
6.250% senior notes due 2022
6.625% senior notes due 2023
6.250% senior notes due 2024
Total
(a) Includes payment for accrued interest.
(b) $186 million of the redemptions financed by cash on hand.
(c) $193 million of the redemptions financed by cash on hand.
Senior Notes Outstanding
Principal
Repurchased
Cash Paid (a)
Average Early
Redemption
Percentage
$
$
$
641
1,058
922
108
67
171
2,967
$
706
1,129
978
105
64
163
3,145
107.89%
103.12%
104.00%
94.73%
94.13%
94.52%
As of December 31, 2017, NRG had the following outstanding issuances of senior notes, or Senior Notes:
i.
ii.
iii.
iv.
v.
6.250% senior notes, issued January 27, 2014 and due July 15, 2022, or the 2022 Senior Notes;
6.250% senior notes, issued April 21, 2014 and due November 1, 2024, or the 2024 Senior Notes;
7.250% senior notes, issued May 23, 2016 and due May 15, 2026, or the 2026 Senior Notes;
6.625% senior notes, issued August 2, 2016 and due January 15, 2027, or the 2027 Senior Notes; and
5.750% senior notes, issued December 7, 2017 and due January 15, 2028, or the 2028 Senior Notes.
as guarantors.
The indentures and the forms of notes provide, among other things, that the Senior Notes will be senior unsecured obligations
of NRG. The indentures also provide for customary events of default, which include, among others: nonpayment of principal or
interest; breach of other agreements in the indentures; defaults in failure to pay certain other indebtedness; the rendering of
judgments to pay certain amounts of money against NRG and its subsidiaries; the failure of certain guarantees to be enforceable;
and certain events of bankruptcy or insolvency. Generally, if an event of default occurs, the Trustee or the Holders of at least
25% in principal amount of the then outstanding series of Senior Notes may declare all of the Senior Notes of such series to be
due and payable immediately. The terms of the indentures, among other things, limit NRG's ability and certain of its subsidiaries'
ability to return capital to stockholders, grant liens on assets to lenders and incur additional debt. Interest is payable semi-annually
on the Senior Notes until their maturity dates.
2022 Senior Notes
At any time prior to July 15, 2017, NRG may redeem up to 35% of the aggregate principal amount of the 2022 Senior Notes,
at a redemption price equal to 106.25% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an
amount equal to the net cash proceeds of certain equity offerings. At any time prior to July 15, 2018, NRG may redeem all or a
part of the 2022 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the
redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess
of the principal amount of the note over the following: the present value of 103.125% of the note, plus interest payments due on
the note from the date of redemption through July 15, 2018, computed using a discount rate equal to the Treasury Rate as of such
redemption date plus 0.50%. In addition, on or after July 15, 2018, NRG may redeem some or all of the notes at redemption
prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the
notes redeemed to the first applicable redemption date:
Redemption Period
July 15, 2018 to July 14, 2019
July 15, 2019 to July 14, 2020
July 15, 2020 and thereafter
2024 Senior Notes
Redemption
Percentage
103.125%
101.563%
100.000%
At any time prior to May 1, 2017, NRG may redeem up to 35% of the aggregate principal amount of the 2024 Senior Notes,
at a redemption price equal to 106.25% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with an
amount equal to the net cash proceeds of certain equity offerings. At any time prior to May 1, 2019, NRG may redeem all or a
part of the 2024 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the
redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess
of the principal amount of the note over the following: the present value of 103.125% of the note, plus interest payments due on
the note from the date of redemption through May 1, 2019 computed using a discount rate equal to the Treasury Rate as of such
redemption date plus 0.50%. In addition, on or after May 1, 2019, NRG may redeem some or all of the notes at redemption prices
expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes
redeemed to the first applicable redemption date:
Redemption Period
May 1, 2019 to April 30, 2020
May 1, 2020 to April 30, 2021
May 1, 2021 to April 30, 2022
May 1, 2022 and thereafter
Redemption
Percentage
103.125%
102.083%
101.042%
100.000%
172
173
2026 Senior Notes
At any time prior to May 15, 2019, NRG may redeem up to 35% of the aggregate principal amount of the 2026 Senior
Notes, at a redemption price equal to 107.25% of the principal amount of the notes redeemed, plus accrued and unpaid interest,
with an amount equal to the net cash proceeds of certain equity offerings. At any time prior to May 15, 2021, NRG may redeem
all or a part of the 2026 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest
to the redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the
excess of the principal amount of the note over the following: the present value of 103.625% of the note, plus interest payments
due on the note from the date of redemption through May 15, 2021 computed using a discount rate equal to the Treasury Rate as
of such redemption date plus 0.50%. In addition, on or after May 15, 2021, NRG may redeem some or all of the notes at redemption
prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the
notes redeemed to the first applicable redemption date:
Redemption Period
May 15, 2021 to May 14, 2022
May 15, 2022 to May 14, 2023
May 15, 2023 to May 14, 2024
May 15, 2024 and thereafter
2027 Senior Notes
Redemption
Percentage
103.625%
102.417%
101.208%
100.000%
At any time prior to July 15, 2019, NRG may redeem up to 35% of the aggregate principal amount of the 2027 Senior Notes,
at a redemption price equal to 106.625% of the principal amount of the notes redeemed, plus accrued and unpaid interest, with
an amount equal to the net cash proceeds of certain equity offerings. At any time prior to July 15, 2021 NRG may redeem all or
a part of the 2027 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest to the
redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the excess
of the principal amount of the note over the following: the present value of 103.313% of the note, plus interest payments due on
the note from the date of redemption through July 15, 2021 computed using a discount rate equal to the Treasury Rate as of such
redemption date plus 0.50%. In addition, on or after July 15, 2021, NRG may redeem some or all of the notes at redemption
prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the
notes redeemed to the first applicable redemption date:
Redemption Period
July 15, 2021 to July14, 2022
July 15, 2022 to July 14, 2023
July 15, 2023 to July 14, 2024
July 15, 2024 and thereafter
2028 Senior Notes
Redemption
Percentage
103.313%
102.208%
101.104%
100.000%
At any time prior to January 15, 2021, NRG may redeem up to 35% of the aggregate principal amount of the 2028 Senior
Notes, at a redemption price equal to 105.750% of the principal amount of the notes redeemed, plus accrued and unpaid interest,
with an amount equal to the net cash proceeds of certain equity offerings. At any time prior to January 15, 2023 NRG may redeem
all or a part of the 2028 Senior Notes, at a redemption price equal to 100% of the principal amount, accrued and unpaid interest
to the redemption date, plus a premium. The premium is the greater of: (i) 1% of the principal amount of the notes; or (ii) the
excess of the principal amount of the note over the following: the present value of 102.875% of the note, plus interest payments
due on the note from the date of redemption through January 15, 2023 computed using a discount rate equal to the Treasury Rate
as of such redemption date plus 0.50%. In addition, on or after January 15, 2023, NRG may redeem some or all of the notes at
redemption prices expressed as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest
on the notes redeemed to the first applicable redemption date:
Redemption Period
January 15, 2023 to January 14, 2024
January 15, 2024 to January 14, 2025
January 15, 2025 to January 14, 2026
January 15, 2026 and thereafter
Senior Credit Facility
Redemption
Percentage
102.875%
101.917%
100.958%
100.000%
On June 30, 2016, NRG replaced its Senior Credit Facility, consisting of its Term Loan Facility and Revolving Credit
Facility with a new senior secured facility, or the Senior Credit Facility, which includes the following:
• A $1.9 billion term loan facility, or the 2023 Term Loan Facility, with a maturity date of June 30, 2023, which will pay
interest at a rate of LIBOR plus 2.75%, with a LIBOR floor of 0.75%. The debt was issued at 99.50% of face value;
the discount will be amortized to interest expense over the life of the loan. Repayments under the 2023 Term Loan
Facility will consist of 0.25% of principal per quarter, with the remainder due at maturity. The proceeds of the new term
loan facility as well as cash on hand were used to repay the 2018 Term Loan Facility balance outstanding. A $21 million
loss on extinguishment of the Term Loan Facility was recorded during the second quarter of 2016, which consisted of
the write-off of previously deferred financing costs. On January 24, 2017, NRG repriced the 2023 Term Loan Facility,
reducing the interest rate margin by 50 basis points to LIBOR plus 2.25%, the LIBOR floor remains 0.75%.
• A $289 million revolving senior credit facility, or the Tranche A Revolving Facility, with a maturity date of July 1, 2018
and a $2.2 billion revolving senior credit facility, or the Tranche B Revolving Facility, with a maturity date of June 30,
2021, which will pay interest at a rate of LIBOR plus 2.25%.
The Senior Credit Facility is guaranteed by substantially all of NRG's existing and future direct and indirect subsidiaries,
with certain customary or agreed-upon exceptions for unrestricted foreign subsidiaries, and certain other subsidiaries, including
GenOn, NRG Yield, Inc. and their respective subsidiaries. The capital stock of these guarantor subsidiaries has been pledged for
the benefit of the Senior Credit Facility's lenders.
The Senior Credit Facility is also secured by first-priority perfected security interests in substantially all of the property
and assets owned or acquired by NRG and its subsidiaries, other than certain limited exceptions. These exceptions include assets
of certain unrestricted subsidiaries, equity interests in certain of NRG's affiliates that have non-recourse debt financing, including
GenOn, NRG Yield, Inc. and their respective subsidiaries, and voting equity interests in excess of 66% of the total outstanding
voting equity interest of certain of NRG's foreign subsidiaries.
Tax Exempt Bonds
Amount in millions, except rates
Indian River Power tax exempt bonds, due 2040
Indian River Power LLC, tax exempt bonds, due 2045
Dunkirk Power LLC, tax exempt bonds, due 2042
City of Texas City, tax exempt bonds, due 2045
Fort Bend County, tax exempt bonds, due 2038
Fort Bend County, tax exempt bonds, due 2042
Total
As of December 31,
2017
2016
Interest Rate %
$
$
$
57
190
59
32
54
73
465
$
57
190
59
22
54
73
455
6.000
5.375
5.875
4.125
4.750
4.750
174
175
Non-Recourse Debt
The following are descriptions of certain indebtedness of NRG's subsidiaries that are outstanding as of December 31, 2017.
All of NRG's non-recourse debt is secured by the assets in the respective project subsidiaries as further described below.
Yield LLC and Yield Operating LLC Revolving Credit Facility
NRG Yield LLC and its direct wholly owned subsidiary, NRG Yield Operating LLC, entered into a senior secured revolving
credit facility, which can be used for cash and for the issuance of letters of credit. At December 31, 2017, there was $55 million
outstanding on the revolver and $74 million of letters of credit issued under the revolving credit facility.
NRG Yield Operating 2026 Senior Notes
On August 18, 2016, NRG Yield Operating LLC issued $350 million of senior unsecured notes, or the NRG Yield Operating
2026 Senior Notes. The NRG Yield Operating 2026 Senior Notes bear interest of 5.00% and mature on September 15, 2026.
Interest on the notes is payable semi-annually on March 15 and September 15 of each year, and will commence on March 15,
2017. The Yield Operating 2026 Senior Notes are senior unsecured obligations of NRG Yield Operating LLC and are guaranteed
by NRG Yield LLC, and by certain of NRG Yield Operating LLC’s wholly owned current and future subsidiaries. A portion of
the proceeds from the 2026 Senior Notes was used to repay NRG Yield Operating LLC's revolving credit facility.
Project Financings
The following are descriptions of certain indebtedness of NRG's project subsidiaries that are outstanding as of December 31,
2017.
Aqua Caliente Holdco Financing Agreement
On February 17, 2017, Agua Caliente Borrower I LLC and Agua Caliente Borrower II LLC, Agua Caliente Holdco, the
indirect owners of the Agua Caliente solar facility, issued $130 million of senior secured notes under the Agua Caliente Holdco
Financing Agreement, or 2038 Agua Caliente Holdco Notes, that bear interest at 5.43% and mature on December 31, 2038. Net
proceeds were distributed to the Company.
Carlsbad Project Financing
On May 26, 2017, Carlsbad Energy Holdings, LLC entered into a note payable agreement with financial institutions for
the issuance of up to $407 million of senior secured notes that bear interest at a rate of 4.12%, and mature on October 31, 2038.
As of December 31, 2017, all $407 million of these notes were outstanding.
Also on May 26, 2017, Carlsbad Energy Holdings, LLC entered into a credit agreement, or the Carlsbad Financing
Agreement, with the issuing banks, for a $194 million construction loan, that will convert to a term loan upon completion of the
project. The Carlsbad Financing Agreement also includes a letter of credit facility with an aggregate principle amount not to
exceed $83 million, and a working capital loan facility with an aggregate principle amount not to exceed $4 million. As of
December 31, 2017, $20 million was outstanding under the construction loan and $29 million in in letters of credit in support of
the project were issued.
Utah Portfolio
As part of the November 2, 2016 utility-scale solar and wind acquisition, as discussed in Note 3, Discontinued Operations,
Acquisitions and Dispositions, NRG recorded $222 million of non-recourse project level debt. As of term conversion for the
three associated debt facilities, the Company borrowed an additional $65 million of non-recourse debt. Each facility bears interest
of LIBOR plus 2.625% and matures on December 16, 2022.
Thermal Financing
On October 31, 2016, NRG Energy Center Minneapolis LLC, a subsidiary of NRG Yield, Inc., received proceeds of $125
million from the issuance of 3.55% Series D notes due October 31, 2031, or the Series D Notes, and entered into a shelf facility
for the anticipated issuance of an additional $70 million of notes. The Series D Notes are secured by substantially all of the assets
of NRG Energy Center Minneapolis LLC. NRG Thermal LLC has guaranteed the indebtedness and its guarantee is secured by
a pledge of the equity interests in all of NRG Thermal LLC’s subsidiaries. NRG Energy Center Minneapolis LLC distributed the
proceeds of the Series D Notes to NRG Thermal LLC, who in turn distributed the proceeds to NRG Yield Operating LLC to be
utilized for general corporate purposes, including potential acquisitions.
Alta Wind lease financing arrangements
Alta Wind Holdings (Alta Wind II - V) and Alta I have finance lease obligations issued under lease transactions whereby
the respective operating entities sold and leased back undivided interests in specific assets of the projects. All of the assets of
Alta I-V are pledged as collateral under these arrangements. The sale and related lease transactions are accounted for as financing
arrangements as the operating entities have continued involvement with the property.
Amount in millions,
except rates
Non-Recourse Debt
Alta Wind I
Alta Wind II
Alta Wind III
Alta Wind IV
Alta Wind V
Total
Lease Financing Arrangement
Letter of Credit Facility
Amount Outstanding as
of December 31, 2017
Interest Rate
Maturity
Date
Amount Outstanding as
of December 31, 2017
$
$
231
183
191
123
198
926
7.015%
12/30/2034
$
5.696%
6.067%
5.938%
6.071%
12/30/2034
12/30/2034
12/30/2034
6/30/2035
$
16
27
27
19
30
119
Interest Rate
3.00% -
3.25%
1.250%
1.750%
1.750%
1.750%
Maturity
Date
1/5/2021
3/21/2022
various
various
various
Midwest Generation
On April 7, 2016, Midwest Generation, LLC, or MWG, entered into an agreement to sell certain quantities of unforced
capacity that has cleared various PJM Reliability Pricing Model auctions to a trading counterparty for net proceeds of $253
million. MWG will continue to operate the applicable generation facilities and remains responsible for performance penalties
and eligible for performance bonus payments, if any. Accordingly, MWG will continue to account for all revenues and costs as
before; however, the proceeds will be recorded as a financing obligation while capacity payments by PJM to the counterparty
will be reflected as debt amortization and interest expense through the end of the 2018/19 delivery year. MWG will amortize
the upfront discount to interest expense, at an effective interest rate of 4.39%, over the term of the arrangement, through June
2019. As of December 31, 2017, $152 million was outstanding.
CVSR
On July 15, 2016, CVSR Holdco LLC, the indirect owner of the CVSR project, issued $200 million of senior secured notes.
The $199 million of net proceeds from the notes were distributed to a subsidiary of NRG and NRG Yield Operating LLC, the
owners of CVSR Holdco LLC, based on their pro-rata ownership. The notes were issued at par and bear an interest rate at 4.68%.
Interest is payable semi-annually beginning on September 30, 2016, until the maturity date of March 31, 2037.
Capistrano Refinancing
On July 13, 2016, Cedro Hill, Broken Bow and Crofton Bluffs, subsidiaries of Capistrano Wind Partners, each amended
their respective credit facilities to increase borrowings to a total of $312 million and to lower their respective interest rates. The
net proceeds of $87 million were distributed to Capistrano Wind Partners and subsequently distributed to the holders of the Class
B preferred equity interests of Capistrano Wind Partners.
176
177
Interest Rate Swaps — Project Financings
Note 13 — Asset Retirement Obligations
Many of NRG's project subsidiaries entered into interest rate swaps, intended to hedge the risks associated with interest
rates on non-recourse project level debt. These swaps amortize in proportion to their respective loans and are floating for fixed
where the project subsidiary pays its counterparty the equivalent of a fixed interest payment on a predetermined notional value
and will receive quarterly the equivalent of a floating interest payment based on the same notional value. All interest rate swap
payments by the project subsidiary and its counterparty are made quarterly, and the LIBOR is determined in advance of each
interest period. The following table summarizes the swaps, some of which are forward starting as indicated, related to NRG's
project level debt as of December 31, 2017.
% of
Principal
Fixed
Interest
Rate
Floating Interest Rate
Notional Amount at
December 31, 2017
(In millions)
Effective Date
Maturity Date
85% various
1-mo. LIBOR
$
1,000
June 30, 2016
June 30, 2021
Recourse Debt
NRG Energy
Non-Recourse Debt
El Segundo Energy Center
75% various
3-mo. LIBOR
South Trent Wind LLC
South Trent Wind LLC
NRG Solar Roadrunner LLC
NRG Solar Alpine LLC
75%
75%
3.265% 3-mo. LIBOR
4.95% 3-mo. LIBOR
75%
85% various
4.313% 3-mo. LIBOR
3-mo. LIBOR
340
40
21
26
115
various
June 15, 2010
June 30, 2020
various
June 14, 2020
June 14, 2028
September 30, 2011
various
December 31, 2029
various
NRG Solar Avra Valley LLC
85%
2.333% 3-mo. LIBOR
46 November 30, 2012
November 30, 2030
NRG Marsh Landing
Utah Portfolio
DGPV 4
Other
EME Project Financings
Broken Bow
Cedro Hill
Crofton Bluffs
Laredo Ridge
Tapestry
Tapestry
Viento Funding II
Viento Funding II
Walnut Creek Energy
WCEP Holdings
Alta Wind Project Financings
AWAM
Total
75%
80% various
3.244% 3-mo. LIBOR
1-mo. LIBOR
85% various
3-mo. LIBOR
75% various
various
75% various
3-mo. LIBOR
90% various
3-mo. LIBOR
75% various
3-mo. LIBOR
75%
75%
50%
2.310% 3-mo. LIBOR
2.210% 3-mo. LIBOR
3.570% 3-mo. LIBOR
90% various
6-mo. LIBOR
90%
4.985% 6-mo. LIBOR
75% various
3-mo. LIBOR
90%
4.003% 3-mo. LIBOR
100%
2.470% 3-mo. LIBOR
$
295
223
95
653
—
55
136
36
75
June 28, 2013
various
June 30, 2023
September 30, 2036
various
various
various
various
various
various
various
various
various
various
March 31, 2011
March 31, 2026
146 December 30, 2011
December 21, 2021
60 December 21, 2021
December 21, 2029
148
65
239
45
17
3,876
various
July 11, 2023
June 28, 2013
June 28, 2013
various
June 30, 2028
May 31, 2023
May 21, 2023
May 22, 2013
May 15, 2031
The Company's AROs are primarily related to the future dismantlement of equipment on leased property and environmental
obligations related to nuclear decommissioning, ash disposal, site closures, and fuel storage facilities. In addition, the Company
has also identified conditional AROs for asbestos removal and disposal, which are specific to certain power generation operations.
See Note 6, Nuclear Decommissioning Trust Fund, for a further discussion of the Company's nuclear decommissioning
obligations. Accretion for the nuclear decommissioning ARO and amortization of the related ARO asset are recorded to the Nuclear
Decommissioning Trust Liability to the ratepayers and are not included in net income, consistent with regulatory treatment.
The following table represents the balance of ARO obligations as of December 31, 2017 and 2016, along with the additions,
reductions and accretion related to the Company's ARO obligations for the year ended December 31, 2017:
Balance as of December 31, 2016
Revisions in estimates for current obligations
Additions
Spending for current obligations
Accretion — Expense
Accretion — Nuclear decommissioning
Balance as of December 31, 2017
(In millions)
735
(3)
9
(21)
35
16
771
$
$
Note 14 — Benefit Plans and Other Postretirement Benefits
NRG sponsors and operates defined benefit pension and other postretirement plans.
NRG pension benefits are available to eligible non-union and union employees through various defined benefit pension
plans. These benefits are based on pay, service history and age at retirement. Most pension benefits are provided through tax-
qualified plans. NRG also provides postretirement health and welfare benefits for certain groups of employees. Cost sharing
provisions vary by the terms of any applicable collective bargaining agreements.
NRG maintains two separate qualified pension plans, the NRG Pension Plan for Bargained Employees and the NRG Pension
Plan. Employees of both NRG and GenOn participate in each of the pension plans, depending upon whether their employment is
covered by a bargaining 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 pension liabilities associated
with GenOn employees.
As described in Note 1, Nature of Business, and Note 3, Discontinued Operations, Acquisitions and Dispositions, NRG and
GenOn entered into a Restructuring Support Agreement and various support agreements, including a transition services agreement,
that provides for a restructuring and recapitalization of the GenOn Entities through a prearranged plan of reorganization and was
approved by the Bankruptcy Court pursuant to an order of confirmation on December 12, 2017. In accordance with the agreements,
NRG will retain GenOn's pension liability for service provided by GenOn employees prior to the completion of the reorganization.
NRG determined that the retention of this liability is probable and has recorded the estimated accumulated pension benefit obligation
as of December 31, 2017 of $92 million in other non-current liabilities with a corresponding loss from discontinued operations.
The balance reflects a contribution of $13 million to the plans with respect to GenOn's employees paid in September 2017. NRG
will also retain the liability for GenOn's post-employment and retiree health and welfare benefits, in an amount up to $25 million.
Retention of this liability is probable and accordingly, NRG has recorded the $25 million in other non-current liabilities with a
corresponding loss from discontinued operations as of December 31, 2017. NRG's obligation for both of these liabilities will be
revalued through and at GenOn's emergence from bankruptcy, with NRG's obligation for the post-employment and retiree health
and welfare plan capped at $25 million.
NRG expects to contribute $31 million to the Company's pension plans in 2018. Of this amount, $13 million related to
employees of GenOn.
178
179
NRG Defined Benefit Plans
Amounts recognized in NRG's balance sheets were as follows:
The annual net periodic benefit cost/(credit) related to NRG's pension and other postretirement benefit plans include the
following components:
Service cost benefits earned
Interest cost on benefit obligation
Expected return on plan assets
Amortization of unrecognized net loss
Net periodic benefit cost
Service cost benefits earned
Interest cost on benefit obligation
Amortization of unrecognized prior service credit
Amortization of unrecognized net (gain)/loss
Curtailment gain
Net periodic benefit (credit)/cost
2017
Year Ended December 31,
Pension Benefits
2016
(In millions)
2015
26
43
(58)
4
15
$
$
30
43
(60)
2
15
$
$
Year Ended December 31,
Other Postretirement Benefits
2017
2016
(In millions)
2015
$
1
4
(9)
(1)
—
(5) $
2
6
(5)
—
—
3
$
$
32
53
(62)
2
25
3
9
(5)
1
(14)
(6)
$
$
$
$
A comparison of the pension benefit obligation, other postretirement benefit obligations and related plan assets for NRG's
plans on a combined basis is as follows:
As of December 31,
Pension Benefits
2017
2016
Other Postretirement
Benefits
2017
2016
Benefit obligation at January 1
Service cost
Interest cost
Plan amendments
Actuarial loss/(gain)
Employee and retiree contributions
Benefit payments
Benefit obligation at December 31
Fair value of plan assets at January 1
Actual return on plan assets
Employee and retiree contributions
Employer contributions
Benefit payments
Fair value of plan assets at December 31
Funded status at December 31 — excess of obligation
over assets
Less: GenOn postretirement obligation(a)
Add: Retained obligation in bankruptcy proceeding(a)
Net obligation for NRG
$
1,241
26
43
—
77
—
(58)
1,329
953
173
—
36
(58)
1,104
(In millions)
$
1,196
30
43
—
40
—
(68)
1,241
916
72
—
33
(68)
953
$
128
1
4
(1)
6
3
(13)
128
—
—
3
10
(13)
—
(225) $
—
—
(225) $
(288) $
—
—
(288) $
(128) $
38
(25)
(115) $
$
$
$
178
2
6
(42)
(2)
3
(17)
128
—
—
3
14
(17)
—
(128)
46
(25)
(107)
Current liabilities
Less: GenOn other postretirement benefits(a)
Total current liabilities
Non-current liabilities
Less: GenOn other postretirement benefits(a)
Total non-current liabilities
As of December 31,
Pension Benefits
Other Postretirement
Benefits
2017
2016
2017
2016
$
$
$
$
— $
—
— $
225
—
225
$
$
(In millions)
— $
—
— $
288
—
288
$
$
7
(3)
4
121
(10)
111
$
$
$
$
8
(5)
3
120
(16)
104
(a) The difference between GenOn's postretirement benefit obligation and NRG's retained obligation of $13 million and $21 million is presented in
noncurrent liabilities for discontinued operations as of December 31, 2017 and 2016, respectively.
Of the amounts recognized in NRG's balance sheet, $92 million and $120 million related to GenOn's pension benefits
obligation as of December 31, 2017 and 2016, respectively, and $25 million related to GenOn's postretirement benefits obligation
as of December 31, 2017 and 2016.
Amounts recognized in NRG's accumulated OCI that have not yet been recognized as components of net periodic benefit
cost were as follows:
Net loss/(gain)
Prior service cost/(credit)
Total accumulated OCI
Less: GenOn (deconsolidated June 14, 2017)
Net accumulated OCI
As of December 31,
Pension Benefits
Other Postretirement
Benefits
2017
2016
2017
2016
$
$
$
53
3
56
(22)
34
$
$
$
(In millions)
94
3
97
(37)
60
$
$
$
(4) $
(37)
(41) $
10
(31) $
Other changes in plan assets and benefit obligations recognized in OCI were as follows:
Year Ended December 31,
Pension
Benefits
Other Postretirement
Benefits
2017
2016
2017
2016
Net actuarial (gain)/loss
Amortization of net actuarial (gain)/loss
Prior service credit
Amortization of prior service cost
Total recognized in OCI
Less: GenOn (deconsolidated June 14, 2017)
Net recognized in OCI
Less: GenOn (deconsolidated June 14, 2017)
Net recognized in net periodic pension (credit)/cost and
OCI
$
$
$
$
(37) $
(4)
—
—
(41) $
$
15
(26) $
15
(11) $
(In millions)
$
28
(2)
—
—
26
$
(17) $
$
9
(17)
$
$
$
$
6
1
(1)
9
15
2
17
3
24
$
13
$
(11)
(45)
(56)
8
(48)
(2)
—
(41)
5
(38)
3
(35)
3
39
(a) The difference between GenOn's postretirement benefit obligation and NRG's retained obligation of $13 million and $21 million is presented in
noncurrent liabilities for discontinued operations as of December 31, 2017 and 2016, respectively.
As a result of GenOn's deconsolidation during 2017, NRG reduced the loss recorded in other comprehensive income by $28
million related to GenOn's pension and other postretirement benefits.
180
181
The Company's estimated unrecognized loss and unrecognized prior service cost for NRG's pension plan that will be
amortized from accumulated OCI to net periodic cost over the next fiscal year is less than $1 million. The Company's estimated
unrecognized gain and unrecognized prior service credit for NRG's postretirement plan that will be amortized from accumulated
OCI to net periodic cost over the next fiscal year is less than $1 million and $7 million, respectively.
The following table presents the balances of significant components of NRG's pension plan:
Projected benefit obligation
Accumulated benefit obligation
Fair value of plan assets
As of December 31,
Pension Benefits
2017
2016
$
(In millions)
$
1,329
1,255
1,104
1,241
1,174
953
NRG's market-related value of its plan assets is the fair value of the assets. The fair values of the Company's pension plan
assets by asset category and their level within the fair value hierarchy are as follows:
Common/collective trust investment — U.S. equity
Common/collective trust investment — non-U.S. equity
Common/collective trust investment — non-core assets
Common/collective trust investment — fixed income
Short-term investment fund
Subtotal fair value
Measured at net asset value practical expedient
Common/collective trust investment — non-U.S. equity
Common/collective trust investment — fixed income
Partnerships/joint ventures
Total fair value
Common/collective trust investment — U.S. equity
Common/collective trust investment — non-U.S. equity
Common/collective trust investment — global equity
Common/collective trust investment — fixed income
Short-term investment fund
Subtotal fair value
Measured at net asset value practical expedient
Common/collective trust investment — non-U.S. equity
Common/collective trust investment — fixed income
Partnerships/joint ventures
Total fair value
Fair Value Measurements as of December 31, 2017
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
Significant
Observable Inputs
(Level 2)
(In millions)
Total
$
$
— $
—
—
—
5
5
$
256
66
178
230
—
730
$
$
$
256
66
178
230
5
735
94
233
42
1,104
Fair Value Measurements as of December 31, 2016
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
Significant
Observable Inputs
(Level 2)
(In millions)
Total
$
$
— $
—
—
—
3
3
$
283
71
104
190
—
648
$
$
$
283
71
104
190
3
651
78
193
31
953
In accordance with ASC 820, the Company determines the level in the fair value hierarchy within which each fair value
measurement in its entirety falls, based on the lowest level input that is significant to the fair value measurement in its entirety.
The fair value of the common/collective trust investments is valued at fair value which is equal to the sum of the market value of
all of the fund's underlying investments. Certain common/collective trust investments have readily determinable fair value as
they publish daily net asset value, or NAV, per share and are categorized as Level 2. Certain other common/collective trust
investments and partnerships/joint ventures use NAV per share, or its equivalent, as a practical expedient for valuation, and thus
have been removed from the fair value hierarchy table.
The following table presents the significant assumptions used to calculate NRG's benefit obligations:
Weighted-Average Assumptions
Discount rate
Rate of compensation increase
Health care trend rate
As of December 31,
Pension Benefits
Other Postretirement Benefits
2017
2016
2017
2016
3.71%
3.00%
—
4.26%
3.00%
—
3.71%
N/A
8.2% grading to
4.5% in 2025
4.29%
N/A
7.0% grading to
5.0% in 2025
The following table presents the significant assumptions used to calculate NRG's benefit expense:
Pension Benefits
Other Postretirement Benefits
As of December 31,
Weighted-Average
Assumptions
Discount rate
Expected return on plan
assets
Rate of compensation
increase
2017
2016
2015
2017
2016
2015
4.26%
4.52%
4.16%
4.29%
4.55%
4.20%
6.85%
6.65%
6.36%
3.00%
3.00%
3.45%
—
—
—
—
—
—
Health care trend rate
—
—
7.0% grading to
5.0% in 2025
7.25% grading
to 5.0% in 2025
8.6% grading to
5.0% in 2023
—
NRG uses December 31 of each respective year as the measurement date for the Company's pension and other postretirement
benefit plans. The Company sets the discount rate assumptions on an annual basis for each of NRG's defined benefit retirement
plans as of December 31. The discount rate assumptions represent the current rate at which the associated liabilities could be
effectively settled at December 31. The Company utilizes the Aon Hewitt AA Above Median, or AA-AM, yield curve to select
the appropriate discount rate assumption for each retirement plan. The AA-AM yield curve is a hypothetical AA yield curve
represented by a series of annualized individual spot discount rates from 6 months to 99 years. Each bond issue used to build this
yield curve must be non-callable, and have an average rating of AA when averaging available Moody's Investor Services, Standard
& Poor's and Fitch ratings.
NRG employs a total return investment approach, whereby a mix of equities and fixed income investments are used to
maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance is established through careful consideration
of plan liabilities, plan funded status, and corporate financial condition. The Investment Committee reviews the asset mix
periodically and as the plan assets increase in future years, the Investment Committee may examine other asset classes such as
real estate or private equity. NRG employs a building block approach to determining the long-term rate of return assumption for
plan assets, with proper consideration given to diversification and rebalancing. Historical markets are studied and long-term
historical relationships between equities and fixed income are preserved, consistent with the widely accepted capital market
principle that assets with higher volatility generate a greater return over the long run. Current factors such as inflation and interest
rates are evaluated before long-term capital market assumptions are determined. Peer data and historical returns are reviewed to
check for reasonableness and appropriateness.
In 2016, NRG changed the approach utilized to estimate the service cost and interest cost components of net periodic benefit
cost for pension and postretirement benefit plans. Historically, the Company estimated these components by using a single weighted
average discount rate derived from the yield curve used to measure the benefit obligation. The Company has elected to use a spot
rate approach in the estimation of the components of benefit cost by applying specific spot rates along the yield curve to the
relevant projected cash flows, as this provides a better estimate of service and interest costs. This election is considered a change
in estimate and, accordingly, has been accounted for starting in 2016. This change does not affect the measurement of NRG's total
benefit obligation.
182
183
The target allocations of NRG's pension plan assets were as follows for the year ended December 31, 2017:
OCI related to its 44% interest in STP:
The Company has recognized the following in its statement of financial position, statement of operations and accumulated
U.S. equity
Non-U.S. equity
Non-core assets
U.S. fixed income
22%
14%
19%
45%
Plan assets are currently invested in a diversified blend of equity and fixed-income investments. Furthermore, equity
investments are diversified across U.S., non-U.S., global, and emerging market equities, as well as among growth, value, small
and large capitalization stocks.
Investment risk and performance are monitored on an ongoing basis through quarterly portfolio reviews of each asset fund
class to a related performance benchmark, if applicable, and annual pension liability measurements. Performance benchmarks
are composed of the following indices:
As of December 31,
Pension Benefits
Other Postretirement Benefits
2017
2016
2017
2016
Funded status — STPNOC benefit plans
Net periodic benefit cost/(credit)
Other changes in plan assets and benefit obligations
recognized in other comprehensive (loss)/income
$
(76) $
8
(6)
Defined Contribution Plans
(In millions)
(74) $
7
11
(24) $
(3)
5
(23)
(2)
(1)
NRG's employees are also eligible to participate in defined contribution 401(k) plans.
Asset Class
Index
The Company's contributions to these plans were as follows:
U.S. equities
Non-U.S. equities
Non-core assets(a)
Fixed income securities
Dow Jones U.S. Total Stock Market Index
MSCI All Country World Ex-U.S. IMI Index
Various (per underlying asset class)
Barclays Capital Long Term Government/Credit Index &
Barclays Strips 20+ Index
Company contributions to defined contribution plans
$
56
$
55
$
53
Year Ended December 31,
2017
2016
(In millions)
2015
(a) Non-Core Assets are defined as diversifying asset classes approved by the Investment Committee that are intended to enhance returns and/or reduce volatility
of the U.S. and non-U.S. equities. Asset classes considered Non-Core include, but may not be limited to: Emerging Market Equity, Emerging Market Debt,
Non-US Developed Market Small Cap, High Yield Fixed Income, Real Estate, Bank Loans, Global Infrastructure and other Alternatives.
NRG's expected future benefit payments for each of the next five years, and in the aggregate for the five years thereafter,
Note 15 — Capital Structure
For the period from December 31, 2014 to December 31, 2017, the Company had 10,000,000 shares of preferred stock
authorized, and 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's common
shares issued and outstanding for each period presented:
are as follows:
2018
2019
2020
2021
2022
2023-2027
Other Postretirement Benefit
Pension
Benefit Payments
Benefit Payments
(In millions)
Medicare Prescription
Drug Reimbursements
$
$
68
71
75
79
82
421
$
7
8
8
8
8
33
—
—
—
—
—
1
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-
percentage-point change in assumed health care cost trend rates would have the following effect:
Effect on total service and interest cost components
Effect on postretirement benefit obligation
STP Defined Benefit Plans
1-Percentage-
Point Increase
1-Percentage-
Point Decrease
$
(In millions)
$
1
9
—
(8)
NRG has a 44% undivided ownership interest in STP, as discussed further in Note 27, Jointly Owned Plants. STPNOC,
which operates and maintains STP, provides its employees a defined benefit pension plan as well as postretirement health and
welfare benefits. Although NRG does not sponsor the STP plan, it reimburses STPNOC for 44% of the contributions made towards
its retirement plan obligations. For the year ended December 31, 2017, NRG reimbursed STPNOC $8 million towards its defined
benefit plans. For the year ended December 31, 2016, NRG reimbursed STPNOC $7 million towards its defined benefit plans. In
2018, NRG expects to reimburse STPNOC $6 million for its contribution towards the plans.
Balance as of December 31, 2014
Shares issued under ESPP
Shares issued under LTIPs
Share repurchases
Balance as of December 31, 2015
Shares issued under ESPP
Shares issued under LTIPs
Balance as of December 31, 2016
Shares issued under ESPP
Shares issued under LTIPs
Balance as of December 31, 2017
Common Stock
Issued
415,506,176
—
1,433,774
—
416,939,950
—
643,875
417,583,825
—
739,309
418,323,134
Common
Treasury
(78,843,552)
283,139
—
(24,189,495)
(102,749,908)
609,094
—
(102,140,814)
560,769
—
(101,580,045)
Outstanding
336,662,624
283,139
1,433,774
(24,189,495)
314,190,042
609,094
643,875
315,443,011
560,769
739,309
316,743,089
The following table summarizes NRG's common stock reserved for the maximum number of shares potentially issuable
based on the conversion and redemption features of the long-term incentive plans as of December 31, 2017:
Equity Instrument
Long-term incentive plans
Common Stock
Reserve Balance
19,597,433
Common stock dividends — In 2015, NRG paid quarterly dividends on the Company's common stock of $0.145 per share,
or $0.58 per share on an annualized basis. In 2016, as part of the 2016 Capital Allocation Program, the Company decreased its
annual common stock dividend by 79% to $0.12 per share for 2016 and 2017. The following table lists the dividends paid per
common share during 2017, 2016 and 2015:
184
185
2017
2016
2015
Fourth
Quarter
Third
Quarter
Second
Quarter
First
Quarter
$
$
$
0.030
0.030
0.145
$
$
$
0.030
0.030
0.145
$
$
$
0.030
0.030
0.145
$
$
$
0.030
0.145
0.145
On January 19, 2018, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, or $0.12 per
share on an annualized basis, payable on February 15, 2018, to stockholders of record as of February 1, 2018.
Employee Stock Purchase Plan — Under the ESPP, eligible employees may elect to withhold up to 10% of their eligible
compensation to purchase shares of NRG common stock at the lesser of 85% of its fair market value on the offering date or 85%
of the fair market value on the exercise date. An offering date occurs each January 1 and July 1. An exercise date occurs each
June 30 and December 31. As of December 31, 2017, there remained 3,107,050 shares of treasury stock reserved for issuance
under the ESPP, and in January of 2018, 175,862 shares of common stock were issued to employee accounts from treasury stock
for the offering period of July 1, 2017 to December 31, 2017. Beginning January 2018, NRG suspended the ESPP.
Share Repurchases — During 2015 and 2014, the Company's board of directors authorized share repurchases of $481 million
of its common stock, which were made as follows:
Board Authorized Share Repurchases
Fourth Quarter 2014
First Quarter 2015
Second Quarter 2015
Third Quarter 2015
Fourth Quarter 2015
Total Board Authorized Share Repurchases
Total number of
shares purchased
Average
price paid
per share (a)
Amounts paid for
shares purchased
(in millions) (a)
1,624,360
$
26.95
$
3,146,484
4,379,907
11,104,184
5,558,920
25,813,855
25.15
24.53
15.06
15.03
$
44
79
107
167
84
481
(a) The average price paid per share and amounts paid for shares purchased exclude the commissions of $0.015 per share paid in connection with the share
repurchase.
Preferred Stock
2.822% Redeemable Preferred Stock
Preferred Stock
On May 24, 2016, NRG entered an agreement with Credit Suisse Group to repurchase 100% of the outstanding shares of its
$344.5 million 2.822% preferred stock. On June 13, 2016, the Company completed the repurchase from Credit Suisse of 100%
of the outstanding shares at a price of $226 million. The transaction resulted in a gain on redemption of $78 million, measured as
the difference between the fair value of the cash consideration paid upon redemption of $226 million and the carrying value of
the preferred stock at the time of the redemption of $304 million. This amount is reflected in net income/(loss) available to NRG
common stockholders in the calculation of earnings per share.
The following table reflects the changes in the Company's redeemable preferred stock balance for the years ended
December 31, 2017, 2016, and 2015:
Balance as of December 31, 2014
Accretion to redemption value
Balance as of December 31, 2015
Accretion to redemption value
Repurchase of 2.822% redeemable preferred stock
Gain on redemption of 2.822% redeemable preferred stock
Balance as of December 31, 2016
Balance as of December 31, 2017
(In millions)
$
$
291
11
302
2
(226)
(78)
—
—
Note 16 — Investments Accounted for by the Equity Method and Variable Interest Entities
Entities that are not Consolidated
NRG accounts for the Company's significant investments using the equity method of accounting. NRG's carrying value of
equity investments can be impacted by impairments, unrealized gains and losses on derivatives and movements in foreign currency
exchange rates, as well as other adjustments.
The following table summarizes NRG's equity method investments as of December 31, 2017:
Name
Avenal Solar Holdings LLC (a)
Desert Sunlight Investment Holdings, LLC (a)
Elkhorn Ridge Wind, LLC (a)
GenConn Energy LLC (a)
Four Brothers Solar, LLC (a)(c)
Granite Mountain Holdings, LLC (a)(c)
Iron Springs Holdings, LLC (a)(c)
Midway-Sunset Cogeneration Company
San Juan Mesa Wind Project, LLC (a)
Watson Cogeneration Company
Gladstone Power Station (b)
Other(d)
Total equity investments in affiliates
(a) Equity method investments owned by NRG Yield
(b) Gladstone Power Station is located in Australia
(c) Economic interest based on cash to be distributed
(d) Refer to Note 10 - Asset Impairments for discussion of NRG's investment in Petra Nova Parish Holdings, LLC.
Undistributed earnings from equity investments
Variable Interest Entities
Economic
Interest
Investment
Balance
(In millions)
50.0% $
25.0%
47.0%
50.0%
50.0%
50.0%
50.0%
50.0%
75.0%
49.0%
37.5%
Various
$
(6)
272
73
102
213
78
54
16
66
21
139
10
1,038
As of December 31,
2017
2016
$
(In millions)
120
$
101
NRG accounts for its interests in certain entities that are considered VIEs under ASC 810, for which NRG is not the primary
beneficiary, under the equity method.
Utility-Scale Solar Portfolio — As described in Note 3, Discontinued Operations, Acquisitions and Dispositions, on November
2, 2016, the Company acquired equity interests in a tax equity financed portfolio comprised of 530 MW of mechanically-complete
solar assets located in Utah, and subsequently sold these interests to NRG Yield, Inc. on March 27, 2017. These equity interests in
Four Brothers Solar, LLC, Granite Mountain Holdings, LLC, and Iron Springs Holdings, LLC are accounted for as equity method
investments as the Company does not have a controlling financial interest. The assets reached commercial operations during the
fourth quarter of 2016 and have 20-year PPAs with PacifiCorp. NRG's maximum exposure to loss is limited to its equity investment,
which was $345 million as of December 31, 2017.
GenConn — NRG owns a 50% interest in GenConn, a limited liability company formed to construct, own and operate two
190-MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites.
GenConn has a $237 million note with an interest rate of 4.73% and a maturity date of July 2041 and a 5-year, $35 million
working capital facility which can be used to issue letters of credit at an interest rate of 1.875%. As of December 31, 2017, $204
million was outstanding under the note and $14 million of letters of credit issued under the working capital facility. The note is
secured by all of the GenConn assets. NRG's maximum exposure to loss is limited to its equity investment, which was $102 million
as of December 31, 2017.
186
187
Other Equity Investments
Note 17 — Earnings/(Loss) Per Share
Gladstone — Through a joint venture, NRG owns a 37.5% interest in Gladstone, a 1,613 MW coal-fueled power generation
facility in Queensland, Australia. The power generation facility is managed by the joint venture participants and the facility is
operated by NRG. Operating expenses incurred in connection with the operation of the facility are funded by each of the participants
in proportion to their ownership interests. Coal is sourced from local mines in Queensland. NRG and the joint venture participants
receive their respective share of revenues directly from the off takers in proportion to the ownership interests in the joint venture.
Power generated by the facility is primarily sold to an adjacent aluminum smelter, with excess power sold to the Queensland
Government owned utility under long term supply contracts. NRG's investment in Gladstone was $139 million as of December 31,
2017.
Entities that are Consolidated
The Company has a controlling financial interest in certain entities which have been identified as VIEs under ASC 810. These
arrangements are primarily related to tax equity arrangements entered into with third-parties in order to finance the cost of solar
energy systems under operating leases and wind facilities eligible for certain tax credits as further described in Note 2, Summary
of Significant Accounting Policies. For one of the tax equity arrangements, the Company has a deficit restoration obligation equal
to $110 million as of December 31, 2017, which would be required to be funded if the arrangement were to be dissolved.
The summarized financial information for the Company's consolidated VIEs consisted of the following:
(In millions)
Current assets
Net property, plant and equipment
Other long-term assets
Total assets
Current liabilities
Long-term debt
Other long-term liabilities
Total liabilities
Redeemable noncontrolling interests
Noncontrolling interests
Net assets less noncontrolling interests
December 31, 2017
December 31, 2016
$
118
$
2,337
658
3,113
96
661
209
966
78
507
87
1,534
954
2,575
59
442
183
684
46
529
$
1,562
$
1,316
Basic earnings/(loss) per common share is computed by dividing net income/(loss) less accumulated preferred stock dividends
by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year
are weighted for the portion of the year that they were outstanding. Diluted earnings/(loss) per share is computed in a manner
consistent with that of basic earnings/(loss) per share while giving effect to all potentially dilutive common shares that were
outstanding during the period.
Dilutive effect for equity compensation and other equity instruments — The outstanding non-qualified stock options, non-
vested restricted stock units, and market stock units are not considered outstanding for purposes of computing basic earnings/
(loss) per share. However, these instruments are included in the denominator for purposes of computing diluted earnings/(loss)
per share under the treasury stock method. The if-converted method was used to determine the dilutive effect of embedded
derivatives in the Company's 2.822% Preferred Stock for the year ended December 31, 2015. During 2016, the Company
repurchased 100% of the outstanding shares of its 2.822% preferred stock.
The reconciliation of NRG's basic earnings/(loss) per share to diluted earnings/(loss) per share is shown in the following
table:
Basic and diluted loss per share attributable to NRG common stockholders
Net loss attributable to NRG Energy, Inc.
Dividends for preferred shares
Gain on redemption of 2.822% redeemable perpetual preferred shares
Loss Available to Common Stockholders
Weighted average number of common shares outstanding
Loss per weighted average common share — basic and diluted
Year Ended December 31,
2017
2016
2015
(In millions, except per share amounts)
$
$
$
(2,153) $
(774) $
(6,382)
—
—
5
(78)
20
—
(2,153) $
(701) $
(6,402)
317
316
329
(6.79) $
(2.22) $
(19.46)
The following table summarizes NRG's outstanding equity instruments that are anti-dilutive and were not included in the
computation of the Company's diluted loss per share:
Equity compensation
Embedded derivative of 2.822% redeemable perpetual preferred stock
Total
Year Ended December 31,
2017
2016
2015
(In millions of shares)
5
—
5
5
—
5
6
16
22
188
189
Note 18 — Segment Reporting
For the Year Ended December 31, 2016
The Company's segment structure reflects how management currently makes financial decisions and allocates resources.
The Company's businesses are segregated as follows: Generation, which includes generation, international and BETM; Retail,
which includes Mass customers and Business Solutions, which includes C&I customers and other distributed and reliability
products; Renewables, which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and corporate activities.
Intersegment sales are accounted for at market.
NRG Yield includes certain of the Company's contracted generation assets. During 2017, NRG Yield acquired several
projects totaling 555 MW for cash consideration of approximately $245 million from NRG. These acquisitions were treated as a
transfer of entities under common control and accordingly, the financial information for years ended December 31, 2017, 2016,
and 2015 have been recast to reflect these changes.
On June 14, 2017, as described in Note 3, Discontinued Operations, Acquisitions and Dispositions, NRG deconsolidated
GenOn for financial reporting purposes. The financial information for years ended December 31, 2017, 2016, and 2015 have been
recast to present GenOn as discontinued operations within the corporate segment.
NRG’s chief operating decision maker, its chief executive officer, evaluates the performance of its segments based on
operational measures including adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA, free
cash flow and capital for allocation, as well as net income/(loss) and net income/(loss) attributable to NRG Energy, Inc.
During the years ended December 31, 2017, 2016 and 2015, the Company had no customer which comprised more than
10% of the Company's consolidated revenues.
For the Year Ended December 31, 2017
Generation(a)
Retail (a)
Renewables(a)
NRG
Yield(a) Corporate(a)
Eliminations
Total
Generation(a) Retail (a) Renewables(a)
Operating revenues(a)
Operating expenses
Depreciation and amortization
Impairment losses
Development costs
$
3,833
$
6,335
$
3,545
516
430
15
5,164
111
1
4
Total operating cost and expenses
4,506
5,280
Other income - affiliate
Loss on sale of assets
Operating (loss)/income
Equity in (losses)/earnings of unconsolidated
affiliates
Impairment losses on investments
Other income, net
Loss on debt extinguishment
Interest expense
(Loss)/income from continuing operations
before income taxes
Income tax (benefit)/expense
Net (loss)/income from continuing
operations
Income from discontinued operations, net of
income tax
—
—
—
(1)
(673)
1,054
(5)
(142)
21
—
(26)
(825)
(1)
(824)
—
(824)
—
—
(6)
—
6
1,054
1
1,053
—
1,053
NRG
Yield(a)
(In millions)
1,035
$
$
Corporate(a)
Eliminations
Total
77
$
(1,174) $
10,512
325
303
185
—
813
—
—
222
60
—
3
—
(284)
1
(1)
2
—
2
323
57
32
30
442
193
(79)
(251)
13
(21)
19
(142)
(495)
(877)
26
(903)
92
(811)
(1,178)
—
—
—
8,396
1,172
702
89
(1,178)
10,359
—
4
17
—
(4)
—
2
19
—
19
19
193
(80)
266
27
(268)
34
(142)
(895)
(978)
5
(983)
92
(891)
406
217
185
54
40
496
—
—
(90)
(58)
(105)
1
—
(98)
(350)
(20)
(330)
—
(330)
$
(In millions)
$ 1,009
424
$
14
$
(971) $
10,629
Net (Loss)/Income
$
$
3,773
3,300
377
1,504
13
5,194
—
20
(1,401)
(14)
(74)
22
—
(29)
(1,496)
2
6,380
5,372
117
7
2
5,498
—
—
882
—
—
1
—
(6)
877
(9)
211
196
154
45
606
—
(5)
(187)
—
—
—
(1)
(98)
(286)
(20)
348
334
44
—
726
—
—
283
71
—
4
(3)
(306)
49
72
220
32
—
7
259
87
1
(157)
6
(5)
11
(49)
(451)
(645)
(37)
(964)
—
—
—
8,487
1,056
1,709
67
(964)
11,319
—
—
(7)
(32)
—
—
—
—
(39)
—
87
16
(587)
31
(79)
38
(53)
(890)
(1,540)
8
Less: Net (loss)/income attributable to
noncontrolling interests and redeemable
noncontrolling interests
Net (loss)/income attributable to
NRG Energy, Inc.
Balance sheet
Equity investments in affiliates
Capital expenditures(b)
Goodwill
Total assets
(a) Inter-segment sales and net derivative gains
and losses included in operating revenues
(b) Includes accruals.
—
(2)
(13)
(54)
18
(66)
(117)
$
$
$
(824) $
1,055
$
(317) $
56
204
522
276
$
— $
26
$
886
12
374
330
12
23
—
$
$
(829) $
85
$
(774)
4
$
— $
1,120
110
—
—
—
997
662
13,514
$
2,332
$
4,921
$
8,962
$
11,891
$
(10,938) $
30,682
$
1,033
$
4
$
24
$
8
$
105
$
— $
1,174
$
(1,498) $
886
$
(266) $
(23) $
(608) $
(39) $
(1,548)
—
(1,498)
—
—
886
2
—
(266)
—
(23)
(789)
(1,397)
— $
(789)
(39)
(2,337)
(103)
(87)
(4)
8
(184)
(1,498) $
884
$
(163) $
64
$
(1,393) $
(47) $
(2,153)
179
481
165
$
— $
4
$
852
$
82
374
521
—
31
—
3
12
—
$
— $
—
—
1,038
1,127
539
7,209
$
2,630
$
5,129
$ 8,283
$
8,919
$
(8,852) $
23,318
$
$
$
$
910
$
5
$
31
$ — $
25
$
— $
971
190
191
Operating revenues(a)
Operating expenses
Depreciation and amortization
Impairment losses
Development costs
Total operating cost and expenses
Other income - affiliate
Gain/(loss) on sale of assets
Operating (loss)/income
Equity in (losses)/earnings of unconsolidated
affiliates
Impairment losses on investments
Other income, net
Loss on debt extinguishment
Interest expense
(Loss)/income from continuing operations
before income taxes
Income tax expense/(benefit)
Net (loss)/income from continuing operations
Loss from discontinued operations, net of
income tax
Net (Loss)/Income
Less: Net income/(loss) attributable to
noncontrolling interests and redeemable
noncontrolling interests
Net (loss)/income attributable to
NRG Energy, Inc.
Balance sheet
Equity investments in affiliates
Capital expenditures (b)
Goodwill
Total assets
(a) Inter-segment sales and net derivative gains
and losses included in operating revenues
(b) Includes accruals.
For the Year Ended December 31, 2015
Note 19 — Income Taxes
Renewables(a) NRG Yield(a) Corporate(a)
(In millions)
$
968
383
38
$
$
Generation(a)
Retail(a)
$
5,179
$
6,913
4,198
693
4,655
26
9,572
—
21
(4,372)
10
(14)
18
—
—
(25)
(4,383)
—
$
(4,383)
—
(4,383)
6,138
132
36
4
6,310
—
—
603
—
—
(4)
—
—
2
601
1
600
—
600
Operating revenues(a)
Operating expenses
Depreciation and amortization
Impairment losses
Development costs
Total operating costs and expenses
Other income - affiliate
Gain on postretirement benefits curtailment
Operating (loss)/income
Equity in earnings/(losses)of unconsolidated
affiliates
Impairment losses on investments
Other income, net
Loss on sale of equity method investment
Loss on debt extinguishment
Interest expense
(Loss)/income from continuing operations
before income taxes
Income tax expense/(benefit)
Net (loss)/income from continuing
operations
Loss from discontinued operations, net of
income tax
Net (Loss)/Income
Less: Net income/(loss) attributable to
noncontrolling interests and redeemable
noncontrolling interests
Net (loss)/income attributable to
NRG Energy, Inc.
(a) Inter-segment sales and net derivative gains
and losses included in operating revenues
Eliminations
Total
$
(1,153) $ 12,328
(1,135)
10,228
—
22
—
1,351
4,860
154
(1,113)
16,593
—
—
193
21
502
47
133
63
745
193
—
(514)
(40)
(4,051)
—
(42)
13
(14)
19
(574)
(1,112)
1,350
(2,462)
(105)
(2,567)
2
—
(7)
—
—
6
(39)
—
36
(56)
26
(14)
10
(937)
(4,986)
1,345
(39)
(6,331)
—
(39)
(105)
(6,436)
187
176
13
61
437
—
—
(54)
(7)
—
3
—
—
(79)
(137)
(18)
(119)
—
(119)
338
303
1
—
642
—
—
326
31
—
3
—
(9)
(267)
84
12
72
—
72
19
The income tax provision from continuing operations consisted of the following amounts:
Current
State
Total — current
Deferred
U.S. Federal
State
Foreign
Total — deferred
Total income tax expense
Effective tax rate
Year Ended December 31,
2017
2016
2015
(In millions, except percentages)
$
$
$
$
19
19
(6)
(7)
2
(11)
8
(0.5)%
$
$
6
6
3
(6)
2
(1)
5
(0.5)%
9
9
1,020
315
1
1,336
1,345
(27.0)%
The following represents the domestic and foreign components of loss before income tax expense:
U.S.
Foreign
Total
Year Ended December 31,
2017
2016
(In millions)
2015
$
$
(1,557) $
17
(1,540) $
(989) $
11
(978) $
(4,997)
11
(4,986)
—
—
6
(37)
(42)
(54)
A reconciliation of the U.S. federal statutory rate of 35% to NRG's effective rate is as follows:
$
$
(4,383) $
600
$
(125) $
53
$
(2,530) $
3
$
(6,382)
896
$
6
$
31
$
29
$
191
$
— $
1,153
Loss before income taxes
Tax at 35%
State taxes
Foreign operations
Federal and state tax credits, excluding PTCs
Tax Act - corporate income tax rate change
Valuation allowance due to corporate income tax rate change
Valuation allowance - current period activities
Impact of non-taxable equity earnings
Book goodwill impairment
Net interest accrued on uncertain tax positions
Production tax credits
Recognition of uncertain tax benefits
Tax expense attributable to consolidated partnerships
State rate change including true-up to current period activity
AMT refundable credit
Other
Income tax expense
Effective income tax rate
Year Ended December 31,
2017
2016
2015
(In millions, except percentages)
$
$
(1,540)
(539)
19
2
—
733
(660)
482
(5)
30
—
(20)
(5)
4
18
(64)
13
8
(0.5)%
$
$
$
$
(978)
(342)
—
10
—
—
—
398
22
—
1
(26)
2
(1)
(59)
—
—
5
(0.5)%
(4,986)
(1,745)
(215)
1
(5)
—
—
3,023
(10)
340
(3)
(33)
(15)
12
(7)
—
2
1,345
(27.0)%
192
193
For the year ended December 31, 2017, NRG's overall effective tax rate was different than the statutory rate of 35% primarily
due to tax expense recorded from the revaluation of the existing net deferred tax asset and state taxes, partially offset by the change
in valuation allowance, establishing the AMT credit receivable and the generation of PTC’s from various wind facilities. The tax
expense recorded for revaluation of the net deferred tax asset is required to reflect the reduction in the corporate income tax rate
from 35% to 21% in accordance with the Tax Cuts and Jobs Act of 2017, or the Tax Act.
For the year ended December 31, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily
due to the change in valuation allowance, the impact of non-taxable equity earnings and current state tax expense, partially offset
by the generation of PTCs from various wind facilities.
For the year ended December 31, 2015, NRG's overall effective tax rate was different than the statutory rate of 35% primarily
due to recording of a valuation allowance on the federal and certain state net deferred tax assets that may not be realizable under
a “more likely than not” measurement. In addition, a portion of the book goodwill impairment is classified as a permanent reversal
impacting the effective tax rate.
The temporary differences, which gave rise to the Company's deferred tax assets and liabilities consisted of the following:
Deferred tax liabilities:
Emissions allowances
Derivatives, net
Cumulative translation adjustments
Investment in projects
Discount/premium on notes
Deferred financing costs
Discontinued operations
Total deferred tax liabilities
Deferred tax assets:
Deferred compensation, accrued vacation and other reserves
Difference between book and tax basis of property
Goodwill
Differences between book and tax basis of contracts
Pension and other postretirement benefits
Equity compensation
Bad debt reserve
U.S. capital loss carryforwards
U.S. Federal net operating loss carryforwards
Foreign net operating loss carryforwards
State net operating loss carryforwards
Foreign capital loss carryforwards
Federal and state tax credit carryforwards
Federal benefit on state uncertain tax positions
Intangibles amortization (excluding goodwill)
Derivatives, net
Inventory obsolescence
Other
Discontinued operations
Total deferred tax assets
Valuation allowance
Discontinued operations
Total deferred tax assets, net of valuation allowance
Net deferred tax asset
As of December 31,
2017
2016
(In millions)
$
15
15
—
231
2
2
—
265
141
596
38
68
74
10
14
1
596
66
140
1
376
7
101
—
12
—
—
2,241
(1,863)
—
378
113
$
31
—
11
378
5
2
6
433
256
530
83
60
122
11
12
1
728
63
106
1
446
12
115
106
5
7
2,093
4,757
(2,032)
(2,087)
638
205
$
$
The following table summarizes NRG's net deferred tax position:
As of December 31,
2017
2016
Net deferred tax asset — noncurrent
Net deferred tax liability — noncurrent
Net deferred tax asset
$
$
$
(In millions)
134
(21)
113
$
225
(20)
205
The primary driver for the decrease in the net deferred tax asset from $205 million to $113 million is the revaluation of the
ending balance utilizing a 21% corporate income tax rate instead of a 35% corporate income tax rate pursuant to the Tax Act as
of December 22, 2017. NRG Energy, Inc.’s revaluation is completely offset by its valuation allowance. Since NRG Yield, Inc.
does not have a valuation allowance against its net deferred tax asset, its ending balance remains at December 31, 2017. Additionally,
due to GenOn's petition for bankruptcy on June 14, 2017, its inventory of deferreds is reclassed to discontinued operations for the
year ended December 31, 2016 and is completely deconsolidated for the year ended December 31, 2017.
Deferred tax assets and valuation allowance
Net deferred tax balance — As of December 31, 2017 and 2016, NRG recorded a net deferred tax asset of $1.9 billion and
$2.2 billion, respectively. The Company believes the federal and certain state net deferred tax assets may not be realizable under
a “more likely than not” measurement and as such, a valuation allowance has been recorded to reduce the asset accordingly. The
Company assesses cumulative and forecasted pretax book earnings and the future reversal of existing taxable temporary differences,
including the potential impacts of the recently enacted Tax Act. In December 2017, the SEC staff issued Staff Accounting Bulletin
No. 118, which addresses how a company may recognize provisional amounts for the effect of the changes related to the Tax Act.
Consistent with that guidance, the Company recognized provisional amounts based upon our interpretation of the tax laws and
estimates which require significant judgments.
Based on the Company's assessment of positive and negative evidence, including available tax planning strategies, NRG
believes that it is more likely than not that a benefit will not be realized on $1.8 billion and $2.0 billion of tax assets as of
December 31, 2017, and 2016, respectively, thus a valuation allowance has been recorded. The net deferred tax asset of $113
million is predominantly due to the inclusion of NRG Yield Inc.'s net deferred tax asset consisting primarily of net operating losses.
NOL carryforwards — At December 31, 2017, the Company had tax effected cumulative domestic NOLs consisting of
carryforwards for federal income tax purposes of $596 million and state of $140 million. The Company estimates it will need to
generate future taxable income to fully realize the net federal deferred tax asset before expiration commencing in 2026. In addition,
NRG has cumulative foreign NOL carryforwards of $66 million with no expiration date.
Valuation allowance — As of December 31, 2017, the Company's tax effected valuation allowance was $1.8 billion, consisting
of domestic federal net deferred tax assets of approximately $1.5 billion, domestic state net deferred tax assets of $267 million,
foreign net operating loss carryforwards of $66 million and foreign capital loss carryforwards of approximately $1 million. Based
upon the assessment of cumulative and forecasted pretax book earnings, and the future reversal of existing taxable temporary
differences, it was determined that a valuation allowance was required to be recorded during the year.
Taxes Receivable and Payable
As of December 31, 2017, NRG recorded a current tax payable of $7 million that represents a tax liability due for state
income taxes. NRG has a tax receivable of $1 million, comprised of refunds due from state income tax estimated payments and
return filings for 2017 and 2016, respectively.
Uncertain tax benefits
NRG has identified uncertain tax benefits whose after-tax value is $30 million for which, as of December 31, 2017 and 2016,
NRG has recorded a non-current tax liability of $33 million and $37 million, respectively. The Company recognizes interest and
penalties related to uncertain tax benefits in income tax expense. During the year ended December 31, 2017, the Company
recognized an expense of $1 million in interest. As of December 31, 2017 and 2016, NRG had cumulative interest and penalties
related to these uncertain tax benefits of $3 million and $4 million, respectively.
Tax jurisdictions — NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal
jurisdiction and various state and foreign jurisdictions including operations located in Australia.
194
195
The Company is no longer subject to U.S. federal income tax examinations for years prior to 2015. With few exceptions,
Restricted Stock Units
state and local income tax examinations are no longer open for years before 2010.
The following table reconciles the total amounts of uncertain tax benefits:
Balance as of January 1
Increase due to current year positions
Decrease due to prior year positions
Decrease due to settlements and payments
Uncertain tax benefits as of December 31
Note 20 — Stock-Based Compensation
NRG Energy, Inc. Long-Term Incentive Plan
As of December 31,
2017
2016
(In millions)
$
$
34
4
(8)
—
30
$
$
32
8
—
(6)
34
On April 27, 2017, the NRG LTIP was amended to increase the number of shares available for issuance by 3,000,000. As of
December 31, 2017 and 2016, a total of 25,000,000 and 22,000,000 shares of NRG common stock were authorized for issuance
under the NRG LTIP, respectively. There were 8,724,595 and 7,487,058 shares of common stock remaining available for grants
under the NRG LTIP as of December 31, 2017 and 2016, respectively. The NRG LTIP is subject to adjustments in the event of
reorganization, recapitalization, stock split, reverse stock split, stock dividend, and a combination of shares, merger or similar
change in NRG's structure or outstanding shares of common stock.
Upon adoption of the amended NRG LTIP effective April 27, 2017, no shares of NRG common stock remain available for
future issuance under the NRG GenOn LTIP as of December 31, 2017. There were 5,558,390 shares of NRG common stock
authorized for issuance under the NRG GenOn LTIP as of December 31, 2016. As of December 31, 2017 and 2016, there were
1,369,880 and 960,904 shares of common stock remaining available for grants under the NRG GenOn LTIP, respectively.
Non-Qualified Stock Options
NQSOs granted under the NRG LTIP and the NRG GenOn LTIP typically have three-year graded vesting schedules beginning
on the grant date and become exercisable at the end of the requisite service period. NRG recognizes compensation costs for NQSOs
over the requisite service period for the entire award. The maximum contractual term is 10 years for NRG's outstanding NQSOs.
No NQSOs were granted in 2017, 2016 or 2015.
The following table summarizes the Company's NQSO activity and changes during the year:
Outstanding at December 31, 2016
Forfeited
Exercised
Outstanding at December 31, 2017
Exercisable at December 31, 2017
Shares(a)
Weighted Average
Exercise Price
$
1,522,919
(50,001)
(187,060)
1,285,858
1,285,858
25.03
29.35
20.71
25.49
25.49
Weighted Average
Remaining Contractual
Term
(In years)
Aggregate
Intrinsic Value
(In millions)
3
$
3
3
—
6
6
(a) As of December 31, 2017, 51,207 NQSOs granted to employees of GenOn remain outstanding and exercisable.
The following table summarizes the total intrinsic value of options exercised and the cash received from the exercises of
options:
Total intrinsic value of options exercised
Cash received from options exercised
2017
Year Ended December 31,
2016
(In millions)
2015
$
$
1
4
— $
—
2
9
There were no options exercised during the year ended December 31, 2016.
As of December 31, 2017, RSUs granted under the Company's LTIPs typically have three-year graded vesting schedules
beginning on the grant date. Fair value of the RSUs is based on the closing price of NRG common stock on the date of grant. The
following table summarizes the Company's non-vested RSU awards and changes during the year:
Non-vested at December 31, 2016
Granted
Forfeited
Vested
Non-vested at December 31, 2017
(a) As of December 31, 2017, 20,822 RSUs granted to GenOn employees remain outstanding.
Units(a)
1,980,141
1,247,075
(176,132)
(673,271)
2,377,813
Weighted Average Grant-
Date Fair Value per Unit
19.29
$
12.44
14.98
23.65
14.63
The total fair value of RSUs vested during the years ended December 31, 2017, 2016, and 2015, was $19 million, $11 million
and $10 million, respectively. The weighted average grant date fair value of RSUs granted during the years ended December 31,
2017, 2016, and 2015 was $12.44, $11.54, and $27.31, respectively.
Deferred Stock Units
DSUs represent the right of a participant to be paid one share of NRG common stock at the end of a deferral period established
under the terms of the award. DSUs granted under the Company's LTIPs are fully vested at the date of issuance. Fair value of the
DSUs, which is based on the closing price of NRG common stock on the date of grant, is recorded as compensation expense in
the period of grant.
The following table summarizes the Company's outstanding DSU awards and changes during the year:
Outstanding at December 31, 2016
Granted
Converted to Common Stock
Outstanding at December 31, 2017
(a) There were no DSUs granted to GenOn employees and outstanding as of December 31, 2017.
Units(a)
453,674
120,251
(146,777)
427,148
Weighted Average Grant-
Date Fair Value per Unit
21.54
$
16.76
17.62
21.54
The aggregate intrinsic values for DSUs outstanding as of December 31, 2017, 2016, and 2015 were approximately $12
million, $6 million, and $5 million, respectively. The aggregate intrinsic values for DSUs converted to common stock for the
years ended December 31, 2017, 2016, and 2015 were $4 million, $1 million, and less than a million, respectively. The weighted
average grant date fair value of DSUs granted during the years ended December 31, 2017, 2016, and 2015 was $16.76, $16.85
and $25.14, respectively.
Performance Stock Units
PSUs entitle the recipient to stock upon vesting. The amount of the award is subject to the Company's achievement of certain
performance measures over the vesting period. As of December 31, 2017, non-vested PSUs consist of Market Stock Units, or
MSUs, and Relative Performance Stock Units, or RPSUs.
Relative Performance Stock Units — RPSUs are restricted grants where the quantity of shares increases and decreases
alongside the Company's Total Shareholder Return, or TSR, relative to the TSR of the Company’s current proxy peer group
and the total returns of select indexes, or Peer Group. Each RPSU represents the potential to receive NRG common stock
after the completion of the performance period, typically three years of service from the date of grant. The number of shares
of NRG common stock to be paid (if any) as of the vesting date for each RPSU will depend on the Company’s percentile rank
within the Peer Group. The number of shares of common stock to be paid as of the vesting date for each RPSU is linearly
interpolated for TSR performance between the following points: (i) 0% if ranked below the 25th percentile; (ii) 25% if ranked
at the 25th percentile; (iii) 100% if ranked at the 55th percentile (or the 65th percentile if the Company’s absolute TSR is less
than negative 15%); and (iv) 200% if ranked at the 75th percentile or above. The value of the common stock on the date of
grant is based on the closing price of NRG common stock on the date of grant.
196
197
Market Stock Units — MSUs are restricted grants where the quantity of shares increases and decreases alongside the
Company's TSR. Each MSU represents the potential to receive NRG common stock after the completion of the performance
period, typically three years of service from the date of grant. The number of shares of common stock to be paid as of the
vesting date for each MSU is : (i) zero shares, if the TSR has decreased by more than 25% over the performance period, (ii)
three-quarters of one share, if the TSR has decreased by 25% over the performance period; (iii) interpolated between three-
quarters of one share and one share, if the TSR has decreased less than 25% over the performance period; (iv) one share, if
there is no change in TSR over the performance period; (v) interpolated between one share and two shares, if TSR increases
less than 100% during the performance period; and (vi) two shares, if the TSR increases 100% over the performance period.
The value of the common stock on the date of grant is based on the closing price of NRG common stock on the date of grant.
The Company last granted MSUs during the year ended December 31, 2016.
The following table summarizes the Company's non-vested PSU awards and changes during the year:
Non-vested at December 31, 2016
Granted
Forfeited
Non-vested at December 31, 2017
(a) There were no PSUs granted to GenOn employees and outstanding as of December 31, 2017.
Units(a)
1,282,588
738,830
(162,597)
1,858,821
Weighted Average Grant-
Date Fair Value per Unit
21.47
$
15.91
31.85
18.27
The weighted average grant date fair value of PSUs granted during the years ended December 31, 2017, 2016 and 2015, was
$15.91, $14.73 and $26.68, respectively.
The fair value of PSUs is estimated on the date of grant using a Monte Carlo simulation model and expensed over the service
period, which equals the vesting period. Significant assumptions used in the fair value model with respect to the Company's PSUs
are summarized below:
Expected volatility
Expected term (in years)
Risk free rate
2017
RPSUs
2016
MSUs
43.96%
3
1.5%
34.33%
3
1.31%
For the years ended December 31, 2017 and 2016, expected volatility is calculated based on NRG's historical stock price
volatility data over the period commensurate with the expected term of the PSU, which equals the vesting period.
Supplemental Information
The following table summarizes NRG's total compensation expense recognized for the years presented as well as total non-
vested compensation costs not yet recognized and the period over which this expense is expected to be recognized as of
December 31, 2017, for each of the types of awards issued under the LTIPs. Minimum tax withholdings of $5 million, $5 million,
and $21 million for the years ended December 31, 2017, 2016, and 2015, respectively, are reflected as a reduction to additional
paid-in capital on the Company's consolidated balance sheet and are reflected as operating activities on the Company's consolidated
statement of cash flows.
Award
Compensation Expense
Year Ended December 31,
2016
2017
Non-vested Compensation Cost
Unrecognized
Total Cost
Weighted Average
Recognition Period
Remaining (In years)
As of December 31,
2015
2017
2017
(In millions, except weighted average data)
$
NQSOs(a)
RSUs
DSUs
MSUs
RPSUs
PRSUs(b)
Total(c)
Tax detriment recognized
(a) All NQSOs granted under the Company's LTIP were fully vested as of December 31, 2017, 2016, and 2015.
(b) Phantom Restricted Stock Units, PRSUs, are liability-classified time-based awards that typically vest ratably over a three-year period. The amount to be
paid upon vesting is based on NRG's closing stock price for the period.
(c) Does not include GenOn compensation expense incurred prior to the deconsolidation of GenOn on June 14, 2017, of approximately $1 million for each of
the years ended December 31, 2017, 2016, and 2015, which is recorded in loss from discontinued operations in the Company's consolidated statement of
operations.
— $
22
2
16
—
—
40
(12)
— $
17
2
6
4
15
44
$
(5) $
— $
13
2
3
—
5
23
$
(4) $
—
1.37
—
0.82
1.99
1.51
—
13
—
4
6
14
37
$
$
$
Note 21 — Related Party Transactions
The following table summarizes NRG's material related party transactions with third party affiliates that are included in the
Company's operating revenues, operating costs and other income and expense:
Revenues from Related Parties Included in Operating Revenues
Gladstone
GenConn
Total
Year Ended December 31,
2017
2016
(In millions)
2015
$
$
3
5
8
$
$
2
5
7
$
$
4
4
8
Gladstone — NRG provides services to Gladstone, an equity method investment, under an operations and maintenance
agreement. Fees for services under this contract primarily include recovery of NRG's costs of operating the plant as approved in
the annual budget, as well as a base monthly fee.
GenConn — NRG provides services to GenConn under operations and maintenance agreements with GenConn Devon and
GenConn Middletown that began in June 2010 and June 2011, respectively.
198
199
Services Agreement and Transition Services Agreement with GenOn
Commercial Operations Agreement
The Company provides GenOn with various management, personnel and other services, which include human resources,
regulatory and public affairs, accounting, tax, legal, information systems, treasury, risk management, commercial operations, and
asset management, as set forth in the services agreement with GenOn, or the Services Agreement. The initial term of the Services
Agreement was through December 31, 2013, with an automatic renewal absent a request for termination. The fee charged was
determined based on a fixed amount as described in the Services Agreement and was calculated based on historical GenOn expenses
prior to the NRG Merger. The annual fees under the Services Agreement were approximately $193 million and management has
concluded that this method of charging overhead costs is reasonable. As described in Note 3, Discontinued Operations, Acquisitions
and Dispositions, in connection with the Restructuring Support Agreement, NRG agreed to provide shared services to GenOn
under the Services Agreement for an adjusted annualized fee of $84 million. Beginning on June 14, 2017, and through December
2017, NRG recorded amounts earned for shared services of approximately $5 million per month.
In December 2017, in conjunction with the confirmation of the GenOn Entities' plan of reorganization, the Services Agreement
was terminated and replaced by the transition services agreement. Under the transition services agreement, NRG will continue to
provide the shared services and other separation services at an annualized rate of $84 million, subject to certain credits and
adjustments, until June 30, 2018, which may be extended by GenOn through September 30, 2018. NRG may provide additional
separation services that are necessary for or reasonably related to the operation of GenOn's business after such date, subject to
NRG's prior written consent, not to be unreasonably withheld. For the year ended December 31, 2017, NRG recorded other income
- affiliate related to these services of $87 million prior to the Chapter 11 Filing and $42 million against selling, general and
administrative expenses post-Chapter 11 Filing. For the year ended December 31, 2016, NRG recorded other income - affiliate
related to these services of $193 million.
Also in December 2017, NRG provided GenOn with a $3.5 million credit for services provided under the transition services
agreement and began recording amounts earned of approximately $7 million per month. NRG has also agreed to provide GenOn
with a $28 million credit against amounts owed to NRG under the transition services agreement. The credit is intended to reimburse
GenOn for its payment of financing costs. Any unused amount can be paid in cash at GenOn's request, subject to the terms and
conditions of the transition services agreement.
See Note 3, Discontinued Operations, Acquisitions and Dispositions, for further discussion regarding the December 2017
agreed upon changes to the Restructuring Support Agreement and transition services agreement, based on which NRG recorded
a reserve of $12 million against affiliate receivable balances as of December 31, 2017.
Credit Agreement with GenOn
NRG and GenOn are party to a secured intercompany revolving credit agreement. The intercompany revolving credit
agreement provided for a $500 million revolving credit facility, all of which was available for revolving loans and letters of credit.
At December 31, 2017 and December 31, 2016, $92 million and $272 million, respectively, of letters of credit were issued and
outstanding under the NRG credit agreement for GenOn. Additionally, as of December 31, 2017, there were $125 million of loans
outstanding under the intercompany secured revolving credit facility. As of December 31, 2016, no loans were outstanding under
this intercompany secured revolving credit facility. In addition, the intercompany secured revolving credit facility contains
customary covenants and events of default. As of December 31, 2017, GenOn was in default under the secured intercompany
revolving credit agreement due to the filing of the Chapter 11 Cases.
As a result of the Chapter 11 Cases, no additional revolving loans or letters of credit are available to GenOn. In addition,
NRG agreed to provide GenOn with a letter of credit facility during the pendency of the Chapter 11 Cases, which could be utilized
for required letters of credit in lieu of the intercompany secured revolving credit facility. The letter of credit facility provided
availability of up to $330 million less amounts borrowed and letters of credit provided are required to be cash collateralized at
103% of the letter of credit amount. On July 27, 2017, this letter of credit facility was terminated as GenOn has obtained a separate
letter of credit facility with a third party financial institution. Effective with completion of the reorganization, GenOn must repay
NRG for all revolving loans outstanding, with such amount to be netted against the settlement payment owed from NRG to GenOn.
Accordingly, the affiliate receivable is recorded net within accrued expenses and other current liabilities - affiliate on the
consolidated balance sheet as of December 31, 2017. Interest continues to accrue during the pendency of the Chapter 11 Cases
and borrowings remain secured obligations.
NRG Power Marketing LLC has entered into physical and financial intercompany commodity and hedging transactions with
GenOn and certain of its subsidiaries. Subject to applicable collateral thresholds, these arrangements may provide for the bilateral
exchange of credit support based upon market exposure and potential market movements. The terms and conditions of the
agreements are generally consistent with industry practices and other third party arrangements. As of December 31, 2017, derivative
assets and liabilities associated with these transactions are recorded within NRG's derivative instruments balances on the
consolidated balance sheet, with related revenues and costs within operating revenues and cost of operations, respectively.
Additionally, as of December 31, 2017 and December 31, 2016, the Company had $32 million and $79 million, respectively, of
cash collateral posted in support of energy risk management activities by GenOn.
Note 22 — Commitments and Contingencies
Operating Lease Commitments
Powerton and Joliet Leases
The Company leases 100% interests in the Powerton facility and Unit 7 and Unit 8 of the Joliet facility through 2034 and
2030, respectively, through its indirect subsidiary, Midwest Generation, LLC. The Company accounts for these leases as operating
leases and records lease expense on a straight-line basis over the lease term. In connection with the acquisition of EME, the Company
recorded the out-of-market value as a liability in out-of-market contracts of $159 million. The liability will be amortized through
rent expense on a straight-line basis over the term of the lease. The Company expects to record lease expense, net of amortization
of the out-of-market liability, of approximately $14 million per year through the term of the lease.
Future minimum lease commitments under the Powerton and Joliet operating leases for the years ending after December 31,
2017 are as follows:
Period
2018
2019
2020
2021
2022
Thereafter
Total
Other Operating Leases
(In millions)
1
1
1
3
6
228
240
$
$
NRG leases certain Company facilities and equipment under operating leases, some of which include escalation clauses,
expiring on various dates through 2041. NRG also has certain tolling arrangements to purchase power, which qualify as operating
leases. Certain operating lease agreements include provisions such as scheduled rent increases, leasehold incentives, and rent
concessions over their lease term. The Company recognizes the effects of these scheduled rent increases, leasehold incentives, and
rent concessions on a straight-line basis over the lease term unless another systematic and rational allocation basis is more
representative of the time pattern in which the leased property is physically employed. Lease expense under operating leases was
$81 million, $96 million, and $97 million for the years ended December 31, 2017, 2016, and 2015, respectively.
Future minimum lease commitments under operating leases for the years ending after December 31, 2017 are as follows:
Period
2018
2019
2020
2021
2022
Thereafter
Total (a)
(In millions)
78
80
75
65
64
479
841
$
$
200
201
(a) Amounts in the table exclude future sublease income of $49 million associated with long-term leases for office locations.
Coal, Gas and Transportation Commitments
Nuclear Insurance
NRG has entered into long-term contractual arrangements to procure fuel and transportation services for the Company's
generation assets and for the years ended December 31, 2017, 2016, and 2015, the Company purchased $1.2 billion, $1.2 billion,
and $1.8 billion, respectively, under such arrangements.
As of December 31, 2017, the Company's commitments under such outstanding agreements are as follows:
Period
2018
2019
2020
2021
2022
Thereafter
Total
(In millions)
527
188
150
112
103
296
1,376
$
$
Purchased Power Commitments
NRG has purchased power contracts of various quantities and durations that are not classified as derivative assets and liabilities
and do not qualify as operating leases. These contracts are not included in the consolidated balance sheet as of December 31, 2017.
Minimum purchase commitment obligations are as follows as of December 31, 2017:
Period
2018
2019
2020
2021
2022
Thereafter
Total (a)
(a) As of December 31, 2017, the maximum remaining term under any individual purchased power contract is five years.
First Lien Structure
(In millions)
21
14
12
11
10
—
68
$
$
NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired
in the GenOn and EME (including Midwest Generation) acquisitions, assets held by NRG Yield, Inc. and NRG's assets that have
project-level financing, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from
time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents.
The Company's lien counterparties may have a claim on NRG's assets to the extent market prices exceed the hedged price. As of
December 31, 2017, hedges under the first lien were in-the-money for NRG on a counterparty aggregate basis.
Lignite Contract with Texas Westmoreland Coal Co.
The Company's Limestone facility utilizes a blend of coal including lignite obtained from the Jewett mine, a surface mine
adjacent to the Limestone facility, under a long-term contract with Texas Westmoreland Coal Co., or TWCC. The contract is a
cost-plus arrangement with certain performance incentives and penalties. On August 18, 2016, NRG gave notice to TWCC
terminating the active mining of lignite under the contract, effective on December 31, 2016.
Under the contract, TWCC continues to be responsible for reclamation activities. NRG is responsible for reclamation costs
and has recorded an adequate ARO liability. The Railroad Commission of Texas has imposed a bond obligation of $95.5 million
on TWCC for the reclamation of the mine. Pursuant to the contract with TWCC, NRG supports this obligation through surety
bonds. Additionally, NRG is obligated to provide additional performance assurance if required by the Railroad Commission of
Texas.
STP maintains required insurance coverage for liability claims arising from nuclear incidents pursuant to the Price-Anderson
Act. Effective January 1, 2017, the current liability limit per incident is $13.44 billion, subject to change to account for the effects
of inflation and the number of licensed reactors. An inflation adjustment must be made at least once every five years with the next
due no later than September 10, 2018. Under the Price-Anderson Act, owners of nuclear power plants in the U.S. are required to
purchase primary insurance limits of $450 million for each operating site. In addition, the Price-Anderson Act requires an additional
layer of protection through mandatory participation in a retrospective rating plan for power reactors resulting in an additional $13
billion in funds available for public liability claims. The current maximum assessment per incident, per reactor, is approximately
$127 million, taking into account a 5% adjustment for administrative fees, payable at approximately $19 million per year, per
reactor. NRG would be responsible for 44% of the maximum assessment, or $8 million per year, per reactor, and a maximum of
$112 million per incident. In addition, the U.S. Congress retains the ability to impose additional financial requirements on the
nuclear industry to pay liability claims that exceed $13 billion for a single incident. The liabilities of the co-owners of STP with
respect to the retrospective premium assessments for nuclear liability insurance are joint and several.
STP purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Limited,
or NEIL, an industry mutual insurance company, of which STP is a member. STP has purchased $2.75 billion in limits for nuclear
events and $1.5 billion in limits for non-nuclear events, the maximum available from NEIL. The upper $1.25 billion in limits
(excess of the first $1.5 billion in limits) is a single limit blanket policy shared with two Diablo Canyon nuclear reactors, which
have no affiliation with the Company. This shared limit is not subject to automatic reinstatement in the event of a loss. The NEIL
policy covers both nuclear and non-nuclear property damage events, and a NEIL companion policy provides Accidental Outage
coverage for the co-owners of STP's lost revenue following a property damage event, at a weekly indemnity limit of $2.52 million
per unit up to a maximum of $274.4 million nuclear and $183.5 million non-nuclear, and is subject to an eight-week waiting period.
NRG also purchases an Accidental Outage policy from NEIL, which provides protection for lost revenue due to an insurable event.
This coverage allows for reimbursement up to $1.98 million per week per unit up to a maximum of $215.6 million nuclear and
$144 million non-nuclear, and is subject to an eight-week waiting period. Under the terms of the NEIL policies, member companies
may be assessed up to ten times their annual premium if the NEIL Board of Directors determines their surplus has been depleted
due to the payment of property losses at any of the licensed reactors in a single policy year. NEIL requires that its members maintain
an investment grade credit rating or insure their annual retrospective obligation by providing a financial guarantee, letter of credit,
deposit premium, or an insurance policy. NRG has purchased an insurance policy from NEIL to guarantee the Company's obligation;
however this insurance will only respond to retrospective premium adjustments assessed within twenty-four months after the policy
term, whereas NEIL's Board of Directors can make such an adjustment up to 6 years after the policy expires.
Contingencies
The Company's material legal proceedings are described below. The Company believes that it has valid defenses to these legal
proceedings and intends to defend them vigorously. NRG records reserves for estimated losses from contingencies when information
available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. As applicable,
the Company has established an adequate reserve for the matters discussed below. In addition, legal costs are expensed as incurred.
Management has assessed each of the following matters based on current information and made a judgment concerning its potential
outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless
specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or
amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its
assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable
rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts
that are different from its currently recorded reserves and that such difference could be material.
In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings
arising in the ordinary course of business. In management's opinion, the disposition of these ordinary course matters will not
materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.
Midwest Generation Asbestos Liabilities — The Company, through its subsidiary, Midwest Generation, may be subject to
potential asbestos liabilities as a result of its acquisition of EME. The Company is currently analyzing the scope of potential liability
as it may relate to Midwest Generation. The Company believes that it has established an adequate reserve for these cases.
Energy Plus Holdings — On August 7, 2012, Energy Plus Holdings received a subpoena from the NYAG which generally
sought information and business records related to Energy Plus Holdings' sales, marketing and business practices. Energy Plus
Holdings provided documents and information to the NYAG. On June 22, 2015, the NYAG issued another subpoena seeking
additional information. Energy Plus Holdings provided responsive documents to this second subpoena. On August 28, 2017, the
parties entered into an Assurance of Discontinuance resolving this matter.
202
203
Midwest Generation New Source Review Litigation — In August 2009, the EPA and the Illinois Attorney General, or the
Government Plaintiffs, filed a complaint, or the Governments’ Complaint, in the U.S. District Court for the Northern District of
Illinois alleging violations of CAA PSD requirements by Midwest Generation arising from maintenance, repair or replacement
projects at six Illinois coal-fired electric generating stations performed by Midwest Generation or ComEd, a prior owner of the
stations, including alleged failures to obtain PSD construction permits and to comply with BACT requirements. The Government
Plaintiffs also alleged violations of opacity and PM standards at the Midwest Generation plants. Finally, the Government Plaintiffs
alleged that Midwest Generation violated certain operating permit requirements under Title V of the CAA allegedly arising from
such claimed PSD, opacity and PM emission violations. Several environmental groups intervened as plaintiffs in this litigation and
filed a complaint, or the Intervenors’ Complaint, which alleged opacity, PM and related Title V violations. Midwest Generation
filed a motion to dismiss nine of the ten PSD counts in the Governments’ Complaint, and to dismiss the tenth PSD count to the
extent the Governments’ Complaint sought civil penalties for that count. The trial court granted the motion in March 2010.
In June 2010, the Government Plaintiffs and Intervenors each filed an amended complaint. The Governments’ Amended
Complaint again alleged that Midwest Generation violated PSD (based upon the same projects as alleged in their original complaint,
but adding allegations that the Company was liable as the “successor” to ComEd), Title V and opacity and PM standards. It named
EME and ComEd as additional defendants and alleged PSD violations (again, premised on the same projects) against them. The
Intervenors’ Amended Complaint named only Midwest Generation as a defendant and alleged Title V and opacity/PM violations,
as well as one of the ten PSD violations alleged in the Governments’ Amended Complaint. Midwest Generation again moved to
dismiss all but one of the Government Plaintiffs’ PSD claims and the related Title V claims. Midwest Generation also filed a motion
to dismiss the PSD claim in the Intervenors’ Amended Complaint and the related Title V claims. In March 2011, the trial court
granted Midwest Generation’s partial motion to dismiss the Government Plaintiffs’ PSD claims. The trial court denied Midwest
Generation’s motion to dismiss the PSD claim asserted in the Intervenors’ Amended Complaint, but noted that the plaintiffs would
be required to convince the court that the statute of limitations should be equitably tolled. The trial court did not address other
counts in the amended complaints that allege violations of opacity and PM emission limitations under the Illinois State
Implementation Plan and related Title V claims. The trial court also granted the motions to dismiss the PSD claims asserted against
EME and ComEd.
Following the trial court ruling, the Government Plaintiffs appealed the trial court’s dismissals of their PSD claims, including
the dismissal of nine of the ten PSD claims against Midwest Generation and of the PSD claims against the other defendants. Those
PSD claim dismissals were affirmed by the U.S. Court of Appeals for the Seventh Circuit in July 2013. In addition, in 2012, all
but one of the environmental groups that had intervened in the case dismissed their claims without prejudice. As a result, only one
environmental group remains a plaintiff intervenor in the case. In February 2018, the parties agreed in principal to settle the matter.
After the settlement agreement is signed by all parties (which the Company expects to occur in March 2018) and approved by the
court, Midwest Generation will be required to (x) pay $500,000 to each of the State of Illinois and the Federal Government and (y)
make and maintain certain operational improvements.
Telephone Consumer Protection Act Purported Class Actions — Three purported class action lawsuits have been filed against
NRG Residential Solar Solutions, LLC —one in California and two in New Jersey. The plaintiffs generally allege misrepresentation
by the call agents and violations of the TCPA, claiming that the defendants engaged in a telemarketing campaign placing unsolicited
calls to individuals on the “Do Not Call List.” The plaintiffs seek statutory damages of up to $1,500 per plaintiff, actual damages
and equitable relief. On June 22, 2017, plaintiffs in the California case filed a motion for leave to file a second amended complaint
to substitute new plaintiffs. Defendants filed an opposition to this motion on June 26, 2017. The court granted plaintiffs' motion to
substitute new plaintiffs and on August 1, 2017, defendants filed an answer to the second amended complaint. On August 31, 2017,
the court in the California case agreed that the litigation should be stayed pending final court approval of the New Jersey settlement.
On July 12, 2017, the parties in the New Jersey action reached an agreement in principle to resolve the class allegations which was
confirmed by a term sheet signed by the parties on July 28, 2017. On September 27, 2017, plaintiffs in the New Jersey case filed
their motion for preliminary approval of the class settlement which was approved by the court on November 17, 2017. On February
20, 2018 at the close of the objection deadline, two objections were filed to the Dobkin class settlement.
California Department of Water Resources and San Diego Gas & Electric Company v. Sunrise Power Company LLC — On
January 29, 2016, CDWR and SDG&E filed a lawsuit against Sunrise Power Company, along with NRG and Chevron Power
Corporation. In June 2001, CDWR and Sunrise entered into a 10-year PPA under which Sunrise would construct and operate a
generating facility and provide power to CDWR. At the time the PPA was entered into, Sunrise had a transportation services
agreement, or TSA, to purchase natural gas from Kern River through April 30, 2018. In August 2003, CDWR entered into an
agreement with Sunrise and Kern River in which CDWR accepted assignment of the TSA through the term of the PPA. After the
PPA expired, Kern River demanded that any reassignment be to a party which met certain creditworthiness standards which Sunrise
did not. As such, the plaintiffs brought this lawsuit against the defendants alleging breach of contract, breach of covenant of good
faith and fair dealing and improper distributions. Plaintiffs generally claim damages of $1.2 million per month for the remaining
70 months of the TSA. On April 20, 2016, the defendants filed objections in response to the plaintiffs' complaint. The objections
were granted on June 14, 2016; however, the plaintiffs were allowed to file amended complaints on July 1, 2016. On July 27, 2016,
defendants filed objections to the amended complaints. On November 18, 2016, the court sustained the objections and allowed
plaintiffs another opportunity to file a second amended lawsuit which they did on January 13, 2017. On April 21, 2017, the court
issued an order sustaining the objections without leave to amend. On July 14, 2017, CDWR filed a notice of appeal. On January
10, 2018, CDWR filed its appellate brief.
Braun v. NRG Yield, Inc. — On April 19, 2016, plaintiffs filed a putative class action lawsuit against NRG Yield, Inc., the
current and former members of its board of directors individually, and other parties in California Superior Court in Kern County,
CA. Plaintiffs allege various violations of the Securities Act due to the defendants’ alleged failure to disclose material facts related
to low wind production prior to the NRG Yield, Inc.'s June 22, 2015 Class C common stock offering. Plaintiffs seek compensatory
damages, rescission, attorney’s fees and costs. The Defendants filed objections and a motion challenging jurisdiction on October
18, 2016. On December 1, 2017, the parties agreed to a stipulation which provides the plaintiffs' opposition is due on March 6,
2018 and defendants' reply is due on May 4, 2018.
Ahmed v. NRG Energy, Inc. and the NRG Yield Board of Directors — On September 15, 2016, plaintiffs filed a putative class
action lawsuit against NRG Energy, Inc., the directors of NRG Yield, Inc., and other parties in the Delaware Chancery Court. The
complaint alleges that the defendants breached their respective fiduciary duties with regard to the recapitalization of NRG Yield,
Inc. common stock in 2015. The plaintiffs generally seek economic damages, attorney’s fees and injunctive relief. The defendants
filed a motion to dismiss the lawsuit on December 21, 2016. Plaintiffs filed their objection to the motion to dismiss on February
15, 2017. The defendants' reply was filed on March 24, 2017. The court heard oral argument on defendants' motion to dismiss on
June 20, 2017. On September 7, 2017, the court requested additional briefing which the parties provided on September 21, 2017.
On December 11, 2017, the court dismissed the lawsuit with prejudice, thereby ending the case.
Griffoul v. NRG Residential Solar Solutions — On February 28, 2017, plaintiffs, consisting of New Jersey residential solar
customers, filed a purported class action lawsuit in New Jersey state court. Plaintiffs allege violations of the New Jersey Consumer
Fraud Action and Truth-in-Consumer Contracts, Warranty and Notice Act with regard to certain provisions of their residential solar
contracts. The plaintiffs seek damages and injunctive relief as to the proper allocation of the solar renewable energy credits. On
June 6, 2017, the defendants filed a motion to compel arbitration or dismiss the lawsuit. Plaintiffs filed their opposition on June
29, 2017. On July 14, 2017, the court denied NRG's motion to compel arbitration or dismiss the case. On July 25, 2017, NRG filed
a motion for reconsideration of the appeal, which the court denied. On August 22, 2017, NRG filed a notice of appeal. The appeal
is fully briefed and scheduled for argument on April 24, 2018.
Rice v. NRG — On April 14, 2017, plaintiffs filed a purported class action lawsuit in the U.S. District Court for the Western
District of Pennsylvania against NRG, First Energy Corporation and Matt Canastrale Contracting, Inc. Plaintiffs generally claim
personal injury, trespass, nuisance and property damage related to the disposal of coal ash from GenOn's Elrama Power Plant and
First Energy’s Mitchell and Hatfield Power Plants. Plaintiffs generally seek monetary damages, medical monitoring and remediation
of their property. Plaintiffs filed an amended complaint on August 14, 2017. On October 20, 2017, NRG filed its answer and
affirmative defenses.
Washington-St. Tammany and Claiborne Electric Cooperative v. LaGen — On June 28, 2017, plaintiffs Washington-St.
Tammany Electric Cooperative, Inc. and Claiborne Electric Cooperative, Inc. filed a lawsuit against Louisiana Generating, L.L.C.,
or LaGen, in the United States District Court for the Middle District of Louisiana. The plaintiffs claim breach of contract against
LaGen for allegedly improperly charging the plaintiffs for costs related to the installation and maintenance of certain pollution
control technology. Plaintiffs seek damages for the alleged improper charges and a declaration as to which charges are proper under
the contract. On September 14, 2017, the court issued a scheduling order setting this case for trial on October 21, 2019. LaGen
filed a motion for a more definite statement on September 18, 2017 which the court denied on November 2, 2017. LaGen filed its
answer and affirmative defenses on November 17, 2017.
204
205
GenOn Chapter 11 Cases — On the Petition Date, the GenOn Entities filed voluntary petitions for relief under Chapter 11
of the Bankruptcy Code in the Bankruptcy Court. Under the Restructuring Support Agreement to which the GenOn Entities, NRG
and certain of GenOn's and GenOn Americas Generation's senior unsecured noteholders are parties, each of them supported the
Bankruptcy Court's approval of the plan of reorganization. GenOn has a customary "fiduciary out" under the Restructuring Support
Agreement. If the plan of reorganization is not consummated, NRG may not be entitled to the benefits of the Settlement Agreement
provided under the Restructuring Support Agreement and it will remain subject to any claims of GenOn and the noteholders,
including claims relating to or arising out of any shared services and any other relationships or transactions between the companies.
See Note 3, Discontinued Operations, Dispositions and Acquisitions, for additional information related to the Chapter 11 Cases.
GenOn Noteholders' Lawsuit — On December 13, 2016, certain indenture trustees for an ad hoc group of holders, or the
Noteholders, of the GenOn Energy, Inc. 7.875% Senior Notes due 2017, 9.500% Notes due 2018, and 9.875% Notes due 2020, and
the GenOn Americas Generation, LLC8.50% Senior Notes due 2021 and 9.125% Senior Notes due 2031, along with certain of the
Noteholders, filed a complaint in the Superior Court of the State of Delaware against NRG and GenOn alleging certain claims
related to the Services Agreement between NRG and GenOn. Plaintiffs generally seek return of all monies paid under the Services
Agreement and any other damages that the court deems appropriate. On February 3, 2017, the court entered an order approving a
Standstill Agreement whereby the parties agreed to suspend all deadlines in the case until March 1, 2017. The Standstill Agreement
terminated on March 1, 2017. On April 30, 2017, the Noteholders filed an amended complaint that asserts (i) additional fraudulent
transfer claims in relation to GenOn’s sale of the Marsh Landing project to NRG Yield LLC, (ii) alleged breaches of fiduciary duty
by certain current and former officers and directors of GenOn in relation to the Services Agreement and the alleged usurpation of
corporate opportunities concerning the Mandalay and Canal projects and (iii) claims against NRG for allegedly aiding and abetting
such claimed breaches of fiduciary duties. In addition to NRG and GenOn, the amended complaint names NRG Yield LLC and
certain current and former officers and directors of GenOn as defendants. The plaintiffs, among other things, generally seek return
of all monies paid under the services agreement and any other damages that the court deems appropriate. On December 14, 2017,
a settlement agreement was executed between GenOn and NRG which should ultimately resolve this lawsuit.
Morgantown v. GenOn Mid-Atlantic — On June 8, 2017, Morgantown and Dickerson Owner Lessors filed a lawsuit against
GenOn Mid-Atlantic, LLC, NRG North America LLC, GenOn Americas Generation, LLC, NRG Americas, Inc., GenOn Energy
Holdings, Inc., GenOn Energy, Inc., and NRG Energy, Inc. in New York State Supreme Court. The plaintiffs allege that they were
overcharged by defendants for certain services outlined in a Services Agreement and that defendants caused a Qualified Credit
Support portion of a Participation Agreement, or QCS Agreement, to be violated by causing the transfer of certain money outside
the allowable confines set forth in the QCS Agreement. In addition, plaintiffs claim that the transfers were unfairly executed and
done so in an effort to defraud plaintiffs and hinder their ability to continue to do business. As such, plaintiffs seek, among other
things, the return of certain transferred funds and service charges paid and to bar defendants from executing additional transfers
on plaintiffs’ behalf. On November 7, 2017, the Bankruptcy Court issued an order estimating the claims to be valued at $0. On
December 14, 2017, a settlement agreement was executed between GenOn and NRG which should ultimately resolve this lawsuit.
BTEC v. NRG Texas Power — On July 18, 2017, BTEC New Albany LLC, or BTEC, filed a lawsuit against NRG Texas
Power LLC, or NRG Texas Power, in the Harris County District Court in Texas. On January 15, 2013, the parties entered into a
Membership Interest and Purchase Agreement, or MIPA, whereby BTEC agreed to dismantle, transport and rebuild an electric
power generation facility at the former P.H. Robinson Electric Generating Station in Bacliff, Texas. The MIPA required BTEC to
meet a Guaranteed Commercial Completion Date of May 31, 2016. But even a year later, BTEC had not satisfied all of the
contractually-required acceptance criteria. As a result and given that the MIPA expiration date passed on May 31, 2017, NRG
elected to terminate the contract in June 2017. BTEC claims that NRG Texas Power breached the MIPA by improperly terminating
it, and seeks a declaratory judgment as to the rights and obligations of the parties. In addition, BTEC seeks damages, interest and
attorney’s fees. On August 14, 2017, NRG Texas Power served its answer to the lawsuit. On September 7, 2017, NRG Texas Power
filed a counterclaim seeking damages in excess of $48 million.
GenOn Related Contingencies
Actions Pursued by MC Asset Recovery — With Mirant Corporation's emergence from bankruptcy protection in 2006, certain
actions filed by GenOn Energy Holdings and some of its subsidiaries against third parties were transferred to MC Asset Recovery,
a wholly owned subsidiary of GenOn Energy Holdings. MC Asset Recovery is governed by a manager who is independent of NRG
and GenOn. MC Asset Recovery is a disregarded entity for income tax purposes. Under the remaining action transferred to MC
Asset Recovery, MC Asset Recovery seeks to recover damages from Commerzbank AG and various other banks, or the
Commerzbank Defendants, for alleged fraudulent transfers that occurred prior to Mirant's bankruptcy proceedings. In December
2010, the U.S. District Court for the Northern District of Texas dismissed MC Asset Recovery's complaint against the Commerzbank
Defendants. In January 2011, MC Asset Recovery appealed the District Court's dismissal of its complaint against the Commerzbank
Defendants to the U.S. Court of Appeals for the Fifth Circuit, or the Fifth Circuit. In March 2012, the Fifth Circuit reversed the
District Court's dismissal and reinstated MC Asset Recovery's amended complaint against the Commerzbank Defendants. On
December 10, 2015, the District Court granted summary judgment in favor of the Commerzbank Defendants. On December 29,
2015, MC Asset Recovery filed a notice to appeal this judgment with the Fifth Circuit. On June 1, 2017, the Fifth Circuit affirmed
the District Court's judgment. On June 12, 2017, MC Asset Recovery petitioned the Fifth Circuit for rehearing. The petition for
rehearing was denied and a court order and judgment affirming the District Court's judgments was entered on July 17, 2017. The
bankruptcy court is scheduled to hear a Motion for a Final Decree in the Mirant bankruptcy on April 11, 2018.
Natural Gas Litigation — GenOn is party to several lawsuits, certain of which are class action lawsuits, in state and federal
courts in Kansas, Missouri, Nevada and Wisconsin. These lawsuits were filed in the aftermath of the California energy crisis in
2000 and 2001 and the resulting FERC investigations and relate to alleged conduct to increase natural gas prices in violation of
state antitrust law and similar laws. The lawsuits seek treble or punitive damages, restitution and/or expenses. The lawsuits also
name as parties a number of energy companies unaffiliated with NRG. In July 2011, the U.S. District Court for the District of
Nevada, which was handling four of the five cases, granted the defendants' motion for summary judgment and dismissed all claims
against GenOn in those cases. The plaintiffs appealed to the U.S. Court of Appeals for the Ninth Circuit, or the Ninth Circuit, which
reversed the decision of the District Court. GenOn along with the other defendants in the lawsuit filed a petition for a writ of
certiorari to the U.S. Supreme Court challenging the Ninth Circuit's decision and the U.S. Supreme Court granted the petition. On
April 21, 2015, the U.S. Supreme Court affirmed the Ninth Circuit’s holding that plaintiffs’ state antitrust law claims are not field-
preempted by the federal Natural Gas Act and the Supremacy Clause of the U.S. Constitution. The U.S. Supreme Court left open
whether the claims were preempted on the basis of conflict preemption. The U.S. Supreme Court directed that the case be remanded
to the U.S. District Court for the District of Nevada for further proceedings. On March 7, 2016, class plaintiffs filed their motions
for class certification. Defendants filed their briefs in opposition to class plaintiffs' motions for class certification on June 24, 2016.
On March 30, 2017, the court denied the plaintiffs' motions for class certification. On April 13, 2017, the plaintiffs petitioned the
Ninth Circuit for interlocutory review of the court’s order denying class certification. On June 13, 2017, the Ninth Circuit granted
plaintiffs' petition for interlocutory review. On November 22, 2017, plaintiffs filed their appellate brief. On January 22, 2018, the
defendants filed their opposition brief.
In May 2016 in one of the Kansas cases, the U.S. District Court for the District of Nevada granted the defendants' motion for
summary judgment. Subsequently in December 2016, the plaintiffs filed a notice of appeal with the Ninth Circuit. The appeal has
been fully briefed by the parties and was argued on February 16, 2018. GenOn has agreed to indemnify CenterPoint against certain
losses relating to these lawsuits.
In September 2012, the State of Nevada Supreme Court, which was handling the remaining case, affirmed dismissal by the
Eighth Judicial District Court for Clark County, Nevada of all plaintiffs' claims against GenOn. In February 2013, the plaintiffs in
the Nevada case filed a petition for a writ of certiorari to the U.S. Supreme Court. In June 2013, the U.S. Supreme Court denied
the petition for a writ of certiorari, thereby ending one of the five lawsuits.
Potomac River Environmental Investigation — In March 2013, NRG Potomac River LLC, a subsidiary of GenOn, received
notice that the District of Columbia Department of Environment (now renamed the Department of Energy and Environment, or
DOEE) was investigating potential discharges to the Potomac River originating from the Potomac River Generating facility site,
a site where the generation facility is no longer in operation. In connection with that investigation, DOEE served a civil subpoena
on NRG Potomac River LLC requesting information related to the site and potential discharges occurring from the site. NRG
Potomac River LLC provided various responsive materials. In January 2016, DOEE advised NRG Potomac River LLC that DOEE
believed various environmental violations had occurred as a result of discharges DOEE believes occurred to the Potomac River
from the Potomac River Generating facility site and as a result of associated failures to accurately or sufficiently report such
discharges. DOEE has indicated it believes that penalties are appropriate in light of the violations. NRG Potomac River LLC is
currently reviewing the information provided by DOEE.
206
207
Natixis v. GenOn Mid-Atlantic — On February 16, 2018, Natixis Funding Corp. and Natixis, New York Branch filed a
complaint in the Supreme Court of the State of New York against GenOn Mid-Atlantic, the owner lessors under GenOn Mid-
Atlantic’s operating leases of the Dickerson and Morgantown coal generation units, and the lease indenture trustee under those
leases. The plaintiffs’ allegations against GenOn Mid-Atlantic relate to a payment agreement between GenOn Mid-Atlantic and
Natixis Funding Corp. to procure credit support for the payment of certain lease payments owed pursuant to the GenOn Mid-
Atlantic operating leases for Morgantown and Dickerson. Plaintiffs seek approximately $34 million in damages arising from GenOn
Mid-Atlantic’s purported breach of certain warranties in the payment agreement.
Note 23 — Regulatory Matters
East/West
Montgomery County Station Power Tax — On December 20, 2013, NRG received a letter from Montgomery County,
Maryland requesting payment of an energy tax for the consumption of station power at the Dickerson Facility over the previous
three years. Montgomery County seeks payment in the amount of $22 million, which includes tax, interest and penalties. NRG
disputed the applicability of the tax. On December 11, 2015, the Maryland Tax Court reversed Montgomery County's assessment.
Montgomery County filed an appeal, and on February 2, 2017, the Montgomery County Circuit Court affirmed the decision of
the tax court. On February 17, 2017, Montgomery County filed an appeal to the Court of Special Appeals of Maryland. On February
1, 2018, the court heard oral arguments.
NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such,
NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In
addition, NRG is subject to the market rules, procedures, and protocols of the various ISO and RTO markets in which NRG
participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRG's wholesale
and retail businesses.
California Station Power — As the result of unfavorable final and non-appealable litigation, the Company has accrued a
liability associated with consumption of station power at three of the Company’s power plants in California, after August 30, 2010.
In December 2017, subsidiaries of the Company entered into settlements with SCE for the liabilities associated with the Company's
El Segundo and Long Beach facilities. The Company has established an appropriate reserve pending potential regulatory action
by SDG&E regarding Encina.
In addition to the regulatory proceedings noted below, NRG and its subsidiaries are parties to other regulatory proceedings
arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these
ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash
flows.
National
Zero-Emission Credits for Nuclear Plants in Illinois — In 2016, Illinois enacted a Zero Emission Credit, or ZEC, program
for selected nuclear units in Illinois. In total, the program directs over $2.5 billion over ten years to nuclear plants in Illinois that
would otherwise retire. Pursuant to the legislation, the Illinois Power Agency, or IPA, conducts a competitive solicitation to procure
ZECs, although both the Governor of Illinois and Exelon have already announced that the ZECs will be awarded to two Exelon-
owned nuclear power plants in Illinois. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices
and interfere with the wholesale power market. On February 14, 2017, NRG, along with other companies, filed a complaint in
the U.S. District Court for the Northern District of Illinois alleging that the state program is preempted by federal law and in
violation of the dormant commerce clause. Another plaintiff group filed a similar complaint on the same day. Subsequently, on
March 31, 2017, NRG, along with other companies, filed a motion for preliminary injunction. On April 10, 2017, Exelon, as an
intervenor defendant, and State defendants filed motions to dismiss. On July 14, 2017, Defendants' motions to dismiss were granted.
On July 17, 2017, NRG, along with other companies, filed a notice of appeal to the U.S. Court of Appeals for the Seventh Circuit.
Briefing is complete. Oral argument was held on January 3, 2018, with supplemental briefs filed on January 26, 2018. On February
21, 2018, the Seventh Circuit invited the U.S. to file an amicus brief in the proceeding.
Zero-Emission Credits for Nuclear Plants in New York — On August 1, 2016, the NYSPSC issued its Clean Energy Standard,
or CES, which provided for ZECs which 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. These ZECs are out-of-market subsidies that threaten to artificially suppress
market prices and interfere with the wholesale power market. On October 19, 2016, NRG, along with other companies, 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 March 29, 2017, the U.S. District Court heard oral arguments on a motion to dismiss filed by defendants.
On July 25, 2017, the defendants' motions to dismiss were granted. On August 24, 2017, NRG, along with other plaintiff companies,
filed a notice of appeal to the U.S. Court of Appeals for the Second Circuit. Briefing is complete. Oral argument has been noticed
for March 12, 2018.
Department of Energy's Proposed Grid Resiliency Pricing Rule — On September 29, 2017, the Department of Energy issued
a proposed rulemaking titled the "Grid Resiliency Pricing Rule." The rulemaking directs FERC to take action to reform the ISO/
RTO markets to value certain reliability and resiliency attributes of electric generation resources. On October 2, 2017, FERC
issued a notice inviting comments. On October 4, 2017, FERC staff issued a series of questions requesting commenters to address.
On October 23, 2017, NRG filed comments encouraging FERC to act expeditiously to modernize energy and capacity markets in
a manner compatible with robust competitive markets. On January 8, 2018, FERC terminated the proposed rulemaking and opened
a new rulemaking asking each ISO/RTO to address specific questions focused on grid resilience.
Puente Power Project — On October 5, 2017, the California Energy Commission, or CEC, the agency responsible for
permitting the Puente Power Project, issued a statement on behalf of the committee of two Commissioners overseeing the permitting
process stating their intention to issue a proposed decision that would deny a permit for the Puente Power Project. On October 16,
2017, NRG filed a motion to suspend the permitting proceeding for at least six months, which was granted on November 3, 2017.
During the six month suspension period, which could conceivably be extended, NRG will evaluate the progress of a procurement
process initiated by SCE to replace the Puente Power Project.
Note 24 — 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. The electric generation industry has been facing requirements regarding GHGs, combustion byproducts,
water discharge and use, and threatened and endangered species that have been put in place in recent years. However, under the
current U.S. presidential administration, some of these rules are being reconsidered and reviewed. In general, future laws are
expected to require the addition of emissions controls or other environmental controls or to impose certain restrictions on the
operations of the Company's facilities, which could have a material effect on the Company's consolidated financial position, results
of operations, or cash flows. Federal and state environmental laws generally have become more stringent over time, although this
trend could slow or pause in the near term with respect to federal laws under the current U.S. presidential administration.
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.
208
209
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. On April 18, 2017, the EPA asked the D.C. Circuit to postpone oral argument that
had been scheduled for May 18, 2017 because the EPA is closely reviewing the supplemental finding to determine whether it
should reconsider all or part of the rule. On April 27, 2017, the D.C. Circuit granted EPA's request to postpone the oral argument
and hold the case in abeyance. 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.
Water
In August 2014, the 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 would have imposed more stringent requirements (as individual permits were renewed) for wastewater
streams from flue gas desulfurization, or FGD, fly ash, bottom ash, and flue gas mercury control. In April 2017, the EPA granted
two petitions to reconsider the rule and also administratively stayed some of the deadlines. On September 18, 2017, the EPA
promulgated a final rule that (i) postpones the compliance dates to preserve the status quo for FGD wastewater and bottom ash
transport water by two years to November 2020 until the EPA completes its next rulemaking and (ii) withdrew the April 2017
administrative stay. The legal challenges have been suspended while the EPA reconsiders and likely modifies the rule. Accordingly,
the Company has largely eliminated its estimate of the environmental capital expenditures that would have been required to comply
with permits incorporating the revised guidelines. The Company will revisit these estimates after the rule is revised.
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. On September 13, 2017, the EPA granted the petition for reconsideration that the Utility Solid Waste Activities
Group filed in May 2017. 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, 2017.
East/West 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. 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,
the Company's Closure Report and the Company's Long Term Stewardship Plan. In the second quarter of 2017, the Company
completed the remediation requirements in the remediation plan. The cost of completing the work required by the remediation
plan was within amounts budgeted in early 2016 and remediation was completed 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.
For further discussion of these matters, refer to Note 22, Commitments and Contingencies.
Note 25 — Cash Flow Information
Detail of supplemental disclosures of cash flow and non-cash investing and financing information was:
Interest paid, net of amount capitalized
Income taxes paid (a)
Non-cash investing and financing activities:
Additions/(decrease) to fixed assets for accrued capital expenditures
Year Ended December 31,
2017
2016
2015
(In millions)
$
868
$
890
$
9
70
14
35
924
12
(44)
(a) In 2017, income taxes paid of $11 million are offset by $2 million in income tax refunds. In 2015, income taxes paid of $13 million are offset by $1 million
in income tax refunds.
Note 26 — Guarantees
NRG and its subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine part
of the Company's business activities. Examples of these contracts include asset purchases and sale agreements, commodity sale
and purchase agreements, retail contracts, joint venture agreements, EPC agreements, operation and maintenance agreements,
service agreements, settlement agreements, and other types of contractual agreements with vendors and other third parties, as well
as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and other matters, as
well as breaches of representations, warranties and covenants set forth in these agreements. The Company is obligated with respect
to customer deposits associated with the Company's retail businesses. In some cases, NRG's maximum potential liability cannot
be estimated, since the underlying agreements contain no limits on potential liability.
The following table summarizes the maximum potential exposures that can be estimated for NRG's guarantees, indemnities,
and other contingent liabilities by maturity:
Guarantees
Letters of credit and surety bonds(a)
Asset sales guarantee obligations
Other guarantees
Total guarantees
By Remaining Maturity at December 31,
2017
Under
1 Year
1-3 Years
3-5 Years
Over
5 Years
Total
2016 Total
$
$
1,467
—
—
1,467
$
$
66
—
32
98
$
$
(In millions)
7
257
—
264
$
$
93
55
613
761
$
$
1,633
312
645
2,590
$
$
1,837
677
253
2,767
(a) Excludes$92 million and $272 million of letters of credit issued under the intercompany revolving credit agreement between NRG and GenOn as of
December 31, 2017 and 2016, respectively.
Letters of credit and surety bonds — As of December 31, 2017, NRG and its consolidated subsidiaries were contingently
obligated for a total of $1.6 billion under letters of credit and surety bonds. Most of these letters of credit and surety bonds are
issued in support of the Company's obligations to perform under commodity agreements and obligations associated with future
closure and maintenance of ash sites, as well as for financing or other arrangements. A majority of these letters of credit and surety
bonds expire within one year of issuance, and it is typical for the Company to renew them on similar terms.
The material indemnities, within the scope of ASC 460, are as follows:
Asset sales — The purchase and sale agreements which govern NRG's asset or share investments and divestitures customarily
contain guarantees and indemnifications of the transaction to third parties. The contracts indemnify the parties for liabilities
incurred as a result of a breach of a representation or warranty by the indemnifying party, or as a result of a change in tax laws.
These obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or
estimate at the time of the transaction. In several cases, the contract limits the liability of the indemnifier. NRG has no reason to
believe that the Company currently has any material liability relating to such routine indemnification obligations.
210
211
Other guarantees — NRG has issued other guarantees of obligations including payments under certain agreements with
respect to certain of its unconsolidated subsidiaries, payment or performance by fuel providers and payment or reimbursement of
credit support and deposits. The Company does not believe that it will be required to perform under these guarantees.
Other indemnities — Other indemnifications NRG has provided cover operational, tax, litigation and breaches of
representations, warranties and covenants. NRG has also indemnified, on a routine basis in the ordinary course of business,
consultants or other vendors who have provided services to the Company. NRG's maximum potential exposure under these
indemnifications can range from a specified dollar amount to an indeterminate amount, depending on the nature of the transaction.
Total maximum potential exposure under these indemnifications is not estimable due to uncertainty as to whether claims will be
made or how they will be resolved. NRG does not have any reason to believe that the Company will be required to make any
material payments under these indemnity provisions.
Because many of the guarantees and indemnities NRG issues to third parties and affiliates do not limit the amount or duration
of its obligations to perform under them, there exists a risk that the Company may have obligations in excess of the amounts
described above. For those guarantees and indemnities that do not limit the Company's liability exposure, it may not be able to
estimate what the Company's liability would be, until a claim is made for payment or performance, due to the contingent nature
of these contracts.
Note 27 — Jointly Owned Plants
Certain NRG subsidiaries own undivided interests in jointly-owned plants, as described below. These plants are maintained
and operated pursuant to their joint ownership participation and operating agreements. NRG is responsible for its subsidiaries'
share of operating costs and direct expenses and includes its proportionate share of the facilities and related revenues and direct
expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of the Company's
consolidated financial statements.
The following table summarizes NRG's proportionate ownership interest in the Company's jointly-owned facilities:
As of December 31, 2017
Ownership
Interest
Property, Plant &
Equipment
Accumulated
Depreciation
Construction in
Progress
(In millions unless otherwise stated)
South Texas Project Units 1 and 2, Bay City, TX
44.00% $
Big Cajun II Unit 3, New Roads, LA
Cedar Bayou Unit 4, Baytown, TX
Keystone, Shelocta, PA
Conemaugh, New Florence, PA
58.00%
50.00%
3.70%
3.72%
$
395
202
215
12
14
(207) $
(132)
(75)
—
—
7
—
7
1
1
Note 28 — Unaudited Quarterly Financial Data
Refer to Note 3, Discontinued Operations, Acquisitions and Dispositions, and Note 10, Asset Impairments, for a description
of the effect of unusual or infrequently occurring events during the quarterly periods. Summarized unaudited quarterly financial
data is as follows:
Quarter Ended
2017
December 31
September 30
June 30
March 31
Operating revenues
Operating (loss)/ income
Net (loss)/income from continuing operations
Income/(loss) from discontinued operations
Net (loss)/income
Less: Net loss attributable to noncontrolling interests and
redeemable noncontrolling interests
Net (loss)/income attributable to NRG Energy, Inc.
(Loss)/income available to Common Stockholders
Weighted average number of common shares
outstanding — basic
Income/(loss) from discontinued operations per weighted
average common share — basic
Net (loss)/income per weighted average common
share — basic
Weighted average number of common shares
outstanding — diluted
Income/(loss) from discontinued operations per weighted
average common share — diluted
Net (loss)/income per weighted average common
share — diluted
Operating revenues
Operating (loss)/income
Net (loss)/income from continuing operations
(Loss)/income from discontinued operations
Net (loss)/income
Less: Net loss attributable to noncontrolling interests and
redeemable noncontrolling interests
Net (loss)/income attributable to NRG Energy, Inc.
(Loss)/income available to Common Stockholders
Weighted average number of common shares
outstanding — basic
(Loss)/income from discontinued operations per weighted
average common share — basic
Net (loss)/income per weighted average common
share — basic
Weighted average number of common shares
outstanding — diluted
(Loss)/income from discontinued operations per weighted
average common share — diluted
Net (loss)/income per weighted average common
share — diluted
$
$
$
$
$
$
$
$
$
$
$
$
$
(In millions, except per share data)
2,701
$
343
99
(741)
(642)
3,049
376
190
(27)
163
$
2,497
(1,345)
(1,667)
13
(1,655)
(120)
(1,535)
(1,535) $
317
(8)
171
171
317
$
(16)
(626)
(626) $
316
0.04
$
(0.09) $
(2.34) $
(4.84) $
0.54
$
(1.98) $
317
322
316
0.04
$
(0.08) $
(2.34) $
(4.84) $
0.53
$
(1.98) $
2,382
39
(170)
(34)
(203)
(40)
(163)
(163)
316
(0.11)
(0.52)
316
(0.11)
(0.52)
Quarter Ended
2016
December 31
September 30
June 30
March 31
$
(In millions, except per share data)
2,248
$
164
(163)
(113)
(276)
3,421
429
128
265
393
$
2,184
(658)
(891)
(164)
(1,055)
(68)
(987)
(987) $
316
(0.52) $
(3.12) $
316
(0.52) $
(3.12) $
(9)
402
402
316
0.84
1.27
317
0.84
1.27
$
$
$
$
$
(5)
(271)
(193) $
315
(0.36) $
(0.61) $
315
(0.36) $
(0.61) $
2,659
331
(57)
104
47
(35)
82
77
315
0.33
0.24
315
0.33
0.24
212
213
The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries. NRG conducts
much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make
required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its
subsidiaries and NRG's ability to receive funds from its subsidiaries. Except for NRG Bayou Cove, LLC, which is subject to
certain restrictions under the Company's Peaker financing agreements, there are no restrictions on the ability of any of the guarantor
subsidiaries to transfer funds to NRG. In addition, there may be restrictions for certain non-guarantor subsidiaries.
The following condensed consolidating financial information presents the financial information of NRG Energy, Inc., the
guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 under the SEC's Regulation S-X. The
financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries
or non-guarantor subsidiaries operated as independent entities.
In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor subsidiaries and non-guarantor
subsidiaries of NRG are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired
have been presented on a push-down accounting basis.
In addition, the condensed parent company financial statements are provided in accordance with Rule 12-04, Schedule I of
Regulation S-X, as the restricted net assets of NRG Energy, Inc.’s subsidiaries exceed 25 percent of the consolidated net assets of
NRG Energy, Inc. These statements should be read in conjunction with the consolidated statements and notes thereto of NRG
Energy, Inc. For a discussion of NRG Energy, Inc.'s long-term debt, see Note 12, Debt and Capital Leases to the consolidated
financial statements. For a discussion of NRG Energy, Inc.'s contingencies, see Note 22, Commitments and Contingencies to the
consolidated financial statements. For a discussion of NRG Energy, Inc.'s guarantees, see Note 26, Guarantees to the consolidated
financial statements.
Note 29 — Condensed Consolidating Financial Information
As of December 31, 2017, the Company had outstanding $4.8 billion of Senior Notes due 2022 - 2028, as shown in Note
12, Debt and Capital Leases. These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic
subsidiaries, or guarantor subsidiaries. These guarantees are both joint and several. The non-guarantor subsidiaries include all
of NRG's foreign subsidiaries and certain domestic subsidiaries, including GenOn and its subsidiaries and NRG Yield, Inc. and
its subsidiaries.
Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior
Notes as of December 31, 2017:
NRG Norwalk Harbor Operations Inc.
NRG Operating Services, Inc.
NRG Oswego Harbor Power Operations Inc.
NRG PacGen Inc.
NRG Portable Power LLC
NRG Power Marketing LLC
NRG Reliability Solutions LLC
NRG Renter's Protection LLC
NRG Retail LLC
NRG Retail Northeast LLC
New Genco GP, LLC
Norwalk Power LLC
NRG Advisory Services LLC
NRG Affiliate Services Inc.
NRG Arthur Kill Operations Inc.
NRG Astoria Gas Turbine Operations Inc.
NRG Bayou Cove LLC
NRG Business Services LLC
NRG Cabrillo Power Operations Inc.
NRG California Peaker Operations LLC
NRG Cedar Bayou Development Company, LLC NRG Rockford Acquisition LLC
NRG Connected Home LLC
NRG Connecticut Affiliate Services Inc.
NRG Construction LLC
NRG Curtailment Solutions, Inc
NRG Development Company Inc.
NRG Devon Operations Inc.
NRG Dispatch Services LLC
Ace Energy, Inc.
Allied Home Warranty GP LLC
Allied Warranty LLC
Arthur Kill Power LLC
Astoria Gas Turbine Power LLC
Bayou Cove Peaking Power, LLC
BidURenergy, Inc.
Cabrillo Power I LLC
Cabrillo Power II LLC
Carbon Management Solutions LLC
Cirro Group, Inc.
Cirro Energy Services, Inc.
Conemaugh Power LLC
Connecticut Jet Power LLC
Cottonwood Development LLC
Cottonwood Energy Company LP
Cottonwood Generating Partners I LLC
Cottonwood Generating Partners II LLC
Cottonwood Generating Partners III LLC NRG Distributed Energy Resources Holdings
Cottonwood Technology Partners LP
Devon Power LLC
Dunkirk Power LLC
Eastern Sierra Energy Company LLC
El Segundo Power, LLC
El Segundo Power II LLC
Energy Alternatives Wholesale, LLC
Energy Choice Solutions LLC
Energy Plus Holdings LLC
Energy Plus Natural Gas LLC
Energy Protection Insurance Company
Everything Energy LLC
Forward Home Security, LLC
GCP Funding Company, LLC
Green Mountain Energy Company
Gregory Partners, LLC
Gregory Power Partners LLC
Huntley Power LLC
Independence Energy Alliance LLC
Independence Energy Group LLC
Independence Energy Natural Gas LLC
Indian River Operations Inc.
Indian River Power LLC
Keystone Power LLC
Langford Wind Power, LLC
Louisiana Generating LLC
Meriden Gas Turbines LLC
Middletown Power LLC
Montville Power LLC
NEO Corporation
NRG Distributed Generation PR LLC
NRG Dunkirk Operations Inc.
NRG El Segundo Operations Inc.
NRG Energy Efficiency-L LLC
NRG Energy Labor Services LLC
NRG ECOKAP Holdings LLC
NRG Energy Services Group LLC
NRG Energy Services International Inc.
NRG Energy Services LLC
NRG Generation Holdings, Inc.
NRG Greenco LLC
NRG Home & Business Solutions LLC
NRG Home Services LLC
NRG Home Solutions LLC
NRG Home Solutions Product LLC
NRG Homer City Services LLC
NRG Huntley Operations Inc.
NRG HQ DG LLC
NRG Identity Protect LLC
NRG Ilion Limited Partnership
NRG Ilion LP LLC
NRG International LLC
NRG Maintenance Services LLC
NRG Mextrans Inc.
NRG MidAtlantic Affiliate Services Inc.
NRG Middletown Operations Inc.
NRG Montville Operations Inc.
NRG New Roads Holdings LLC
NRG North Central Operations Inc.
NRG Northeast Affiliate Services Inc.
NRG Saguaro Operations Inc.
NRG Security LLC
NRG Services Corporation
NRG SimplySmart Solutions LLC
NRG South Central Affiliate Services Inc.
NRG South Central Generating LLC
NRG South Central Operations Inc.
NRG South Texas LP
NRG SPV #1 LLC
NRG Texas C&I Supply LLC
NRG Texas Gregory LLC
NRG Texas Holding Inc.
NRG Texas LLC
NRG Texas Power LLC
NRG Warranty Services LLC
NRG West Coast LLC
NRG Western Affiliate Services Inc.
O'Brien Cogeneration, Inc. II
ONSITE Energy, Inc.
Oswego Harbor Power LLC
Reliant Energy Northeast LLC
Reliant Energy Power Supply, LLC
Reliant Energy Retail Holdings, LLC
Reliant Energy Retail Services, LLC
RERH Holdings, LLC
Saguaro Power LLC
Somerset Operations Inc.
Somerset Power LLC
Texas Genco GP, LLC
Texas Genco Holdings, Inc.
Texas Genco LP, LLC
Texas Genco Services, LP
US Retailers LLC
Vienna Operations Inc.
Vienna Power LLC
WCP (Generation) Holdings LLC
West Coast Power LLC
214
215
NRG ENERGY, INC. AND SUBSIDIARIES
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME
For the Year Ended December 31, 2017
For the Year Ended December 31, 2017
Net Loss
Other Comprehensive (Loss)/Income, net of tax
Unrealized gain on derivatives, net
Foreign currency translation adjustments, net
Available-for-sale securities, net
Defined benefit plan, net
Other comprehensive (loss)/income
Comprehensive Loss
Less: Comprehensive loss attributable to
noncontrolling interests and redeemable
noncontrolling interests
Comprehensive Loss Attributable to NRG
Energy, Inc.
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
NRG Energy,
Inc.
(Note Issuer)
(In millions)
Eliminations(a)
Consolidated
Balance
$
(1,001) $
(356) $
(2,169) $
1,189
$
(2,337)
1
6
—
(24)
(17)
(1,018)
13
7
—
29
49
(307)
25
—
(8)
41
58
(2,111)
(26)
(1)
—
—
(27)
1,162
13
12
(8)
46
63
(2,274)
—
(103)
(16)
(60)
(179)
$
(1,018) $
(204) $
(2,095) $
1,222
$
(2,095)
(a) All significant intercompany transactions have been eliminated in consolidation.
Operating Revenues
Total operating revenues
Operating Costs and Expenses
Cost of operations
Depreciation and amortization
Impairment losses
Selling, general and administrative
Reorganization costs
Development costs
Total operating costs and expenses
Other income - affiliate
Gain on sale of assets
Operating (Loss)/Income
Other (Expense)/Income
Equity in (losses)/earnings of consolidated
subsidiaries
Equity in earnings/(losses) of unconsolidated
affiliates
Impairment losses on investments
Other income, net
Net loss on debt extinguishment
Interest expense
Total other expense
Loss from Continuing Operations Before
Income Taxes
Income tax (benefit)/expense
Loss from Continuing Operations
Loss from Discontinued Operations, net of income
tax
Net Loss
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
NRG Energy, Inc.
(Note Issuer)
Eliminations (a)
Consolidated
Balance
(In millions)
$
7,182
$
3,699
$
— $
(252) $
10,629
5,373
405
1,463
371
6
—
7,618
—
4
(432)
(1,162)
—
—
9
—
(14)
(1,167)
(1,599)
(598)
(1,001)
—
(1,001)
2,353
619
246
146
—
49
3,413
—
12
298
(113)
95
(75)
17
(4)
(424)
(504)
(206)
(10)
(196)
(160)
(356)
59
32
—
393
38
18
540
87
—
(453)
(249)
—
—
(3)
—
—
(252)
—
—
—
26
1,249
(4)
(4)
12
(49)
(452)
(471)
(924)
616
(1,540)
(629)
(2,169)
(60)
—
—
—
—
1,189
1,189
—
1,189
—
1,189
7,536
1,056
1,709
907
44
67
11,319
87
16
(587)
—
31
(79)
38
(53)
(890)
(953)
(1,540)
8
(1,548)
(789)
(2,337)
Less: Net loss attributable to noncontrolling
interests and redeemable noncontrolling interests
Net Loss Attributable to NRG Energy, Inc.
$
—
(1,001) $
(108)
(248) $
(16)
(2,153) $
(60)
1,249
$
(184)
(2,153)
(a) All significant intercompany transactions have been eliminated in consolidation.
216
217
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2017
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
NRG Energy, Inc. Eliminations (a) Consolidated
Balance
(In millions)
ASSETS
Current Assets
Cash and cash equivalents
Funds deposited by counterparties
Restricted cash
Accounts receivable - trade
Inventory
Derivative instruments
Cash collateral posted in support of energy risk management
activities
Accounts receivable - affiliate
Current assets held-for-sale
Prepayments and other current assets
Total current assets
Net Property, Plant and Equipment
Other Assets
Investment in subsidiaries
Equity investments in affiliates
Notes receivable, less current portion
Goodwill
Intangible assets, net
Nuclear decommissioning trust fund
Deferred income taxes
Derivative instruments
Non-current assets held-for-sale
Other non-current assets
Total other assets
Total Assets
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and capital leases
Accounts payable
Accounts payable - affiliate
Derivative instruments
Cash collateral received in support of energy risk management
activities
Accrued interest expense
Current liabilities - held-for-sale
Other accrued expenses and other current liabilities
Other accrued expenses and other current liabilities - affiliate
Total current liabilities
Other Liabilities
Long-term debt and capital leases
Nuclear decommissioning reserve
Nuclear decommissioning trust liability
Postretirement and other benefit obligations
Deferred income taxes
Derivative instruments
Out-of-market contracts, net
Non-current liabilities held-for-sale
Other non-current liabilities
Total non-current liabilities
Total Liabilities
Redeemable noncontrolling interest in subsidiaries
Stockholders' Equity
$
$
$
— $
37
4
769
339
625
170
712
8
116
2,780
2,527
(106)
—
—
360
458
692
377
121
—
51
1,953
$
348
—
504
306
193
80
1
210
107
118
1,867
11,169
28
1,036
2
179
1,291
—
(7)
40
43
458
3,070
643
—
—
4
—
9
—
(129)
—
27
554
238
7,581
2
36
—
—
—
(236)
31
—
120
7,534
$
— $
—
—
—
—
(88)
—
(698)
—
—
(786)
(26)
(7,503)
—
(36)
—
(3)
—
—
(20)
—
—
(7,562)
991
37
508
1,079
532
626
171
95
115
261
4,415
13,908
—
1,038
2
539
1,746
692
134
172
43
629
4,995
7,260
$
16,106
$
8,326
$
(8,374) $
23,318
— $
546
752
535
37
3
—
288
—
2,161
244
269
415
118
112
110
66
—
295
1,629
3,790
—
3,470
$
667
280
(202)
108
—
56
72
118
—
1,099
8,733
—
—
1
64
107
141
8
317
9,371
10,470
78
5,558
57
55
181
—
—
97
—
328
161
879
6,739
—
—
339
(155)
—
—
—
52
6,975
7,854
—
472
$
(36) $
—
(698)
(88)
—
—
—
—
—
(822)
—
—
—
—
—
(20)
—
—
—
(20)
(842)
—
(7,532)
688
881
33
555
37
156
72
734
161
3,317
15,716
269
415
458
21
197
207
8
664
17,955
21,272
78
1,968
Total Liabilities and Stockholders' Equity
$
7,260
$
16,106
$
8,326
$
(8,374) $
23,318
(a) All significant intercompany transactions have been eliminated in consolidation.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2017
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
NRG Energy, Inc.
(Note Issuer)
Eliminations(a)
Consolidated
Balance
Cash Flows from Operating Activities
Net loss
Loss from discontinued operations
Net loss from continuing operations
$
$
(1,001)
—
(1,001)
Adjustments to reconcile net loss to net cash provided by operating activities:
Equity in earnings and distributions from unconsolidated affiliates
Depreciation and amortization
Provision for bad debts
Amortization of nuclear fuel
Amortization of financing costs and debt discount/premiums
Adjustment for debt extinguishment
Amortization of intangibles and out-of-market contracts
Amortization of unearned equity compensation
Net gain on sale of assets and equity method investments
Impairment losses
Changes in derivative instruments
Changes in deferred income taxes and liability for uncertain tax benefits
Changes in collateral deposits in support of energy risk management activities
Proceeds from sale of emission allowances
Changes in nuclear decommissioning trust liability
Cash (used)/provided by changes in other working capital
Cash provided by continuing operations
Cash used by discontinued operations
Net Cash Provided by Operating Activities
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.
Acquisition of Drop Down Assets, net of cash acquired
Intercompany dividends
Acquisition of businesses, net of cash acquired
Capital expenditures
Net cash proceeds from notes receivable
Proceeds from renewable energy grants
Proceeds from sale of emission allowances
Investments in nuclear decommissioning trust fund securities
Proceeds from sales of nuclear decommissioning trust fund securities
Proceeds from sale of assets, net
Investments in unconsolidated affiliates
Other
Cash (used)/provided by continuing operations
Cash used by discontinued operations
Net Cash (Used)/Provided by Investing Activities
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.
Payments from/(for) intercompany loans
Acquisition of Drop Down Assets, net of cash acquired
Intercompany dividends
Payment of dividends to common and preferred stockholders
Net receipts from settlement of acquired derivatives that include financing
elements
Payments for debt extinguishment costs
Distributions from, net of contributions to, noncontrolling interest in
subsidiaries
Payments from issuance of common stock
Proceeds from issuance of long-term debt
Payment of debt issuance and hedging costs
Payments for short and long-term debt
Receivable from affiliate
Other
Cash provided/(used) by continuing operations
Cash used by discontinued operations
Net Cash Provided/(Used) by Financing Activities
Effect of exchange rate changes on cash and cash equivalents
Change in cash from discontinued operations
Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted Cash, and
Funds Deposited by Counterparties
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by
Counterparties at Beginning of Period
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited by
Counterparties at End of Period
(a) All significant intercompany transactions have been eliminated in consolidation.
—
405
54
51
—
—
27
—
(18)
1,463
(100)
(300)
(98)
25
11
(363)
156
—
156
—
—
—
(14)
(183)
—
8
66
(512)
501
33
—
18
(83)
—
(83)
—
(45)
—
—
—
—
—
—
—
—
—
—
—
—
(45)
—
(45)
—
—
28
13
(356)
(160)
(196)
5
619
2
—
42
4
81
—
(16)
321
(69)
69
18
—
—
(164)
716
(38)
678
—
(249)
—
(27)
(906)
17
—
—
—
—
54
(40)
(6)
(1,157)
(53)
(1,210)
(94)
13
—
(129)
—
2
—
95
—
1,186
(47)
(647)
(125)
(10)
244
(224)
20
(1)
(315)
(198)
1,050
$
$
(2,169)
(629)
(1,540)
$
1,189
—
1,189
(2,337)
(789)
(1,548)
4
32
12
—
18
49
—
35
—
4
24
322
—
—
—
1,593
553
—
553
94
—
129
—
(22)
—
—
—
—
—
—
—
—
201
—
201
—
32
249
—
(38)
—
(42)
—
(2)
1,084
(16)
(1,701)
—
—
(434)
—
(434)
—
—
320
323
46
—
—
—
—
—
—
—
—
—
(26)
—
—
—
—
(1,209)
—
—
—
(94)
249
(129)
—
—
—
—
—
—
—
—
—
—
26
—
26
94
—
(249)
129
—
—
—
—
—
—
—
—
—
—
(26)
—
(26)
—
—
—
—
55
1,056
68
51
60
53
108
35
(34)
1,788
(171)
91
(80)
25
11
(143)
1,425
(38)
1,387
—
—
—
(41)
(1,111)
17
8
66
(512)
501
87
(40)
12
(1,013)
(53)
(1,066)
—
—
—
—
(38)
2
(42)
95
(2)
2,270
(63)
(2,348)
(125)
(10)
(261)
(224)
(485)
(1)
(315)
150
1,386
$
41
$
852
$
643
$
— $
1,536
218
219
NRG ENERGY, INC. AND SUBSIDIARIES
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME
For the Year Ended December 31, 2016
For the Year Ended December 31, 2016
Net Income/(Loss)
Other Comprehensive Income, net of tax
Unrealized gain on derivatives, net
Foreign currency translation adjustments, net
Available-for-sale securities, net
Defined benefit plan, net
Other comprehensive income
Comprehensive Income/(Loss)
Less: Comprehensive (loss)/income
attributable to noncontrolling interests and
redeemable noncontrolling interests
Comprehensive Income/(Loss) Attributable to
NRG Energy, Inc.
Dividends for preferred shares
Gain on redemption of preferred shares
Comprehensive Income/(Loss) Available for
Common Stockholders
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
NRG Energy, Inc.
(Note Issuer)
Eliminations(a)
Consolidated
Balance
$
567
$
(538) $
(718) $
(202) $
(891)
(In millions)
—
(1)
—
34
33
600
—
600
—
—
32
(1)
—
(13)
18
(520)
(103)
(417)
—
—
89
(1)
1
(51)
38
(680)
56
(736)
5
(78)
(86)
2
—
33
(51)
(253)
(70)
(183)
—
—
35
(1)
1
3
38
(853)
(117)
(736)
5
(78)
$
600
$
(417) $
(663) $
(183) $
(663)
(a) All significant intercompany transactions have been eliminated in consolidation.
Operating Revenues
Total operating revenues
Operating Costs and Expenses
Cost of operations
Depreciation and amortization
Impairment losses
Selling, general and administrative
Development costs
Total operating costs and expenses
Other income - affiliate
Loss on sale of assets
Operating Income/(Loss)
Other (Expense)/Income
Equity in (losses)/earnings of consolidated
subsidiaries
Equity in earnings/(losses) of unconsolidated
affiliates
Impairment losses on investments
Other income, net
Net loss on debt extinguishment
Interest expense
Total other expense
Income/(Loss) from Continuing Operations
Before Income Taxes
Income tax (benefit)/expense
Income/(Loss) from Continuing Operations
Income from Discontinued Operations, net of
income tax
Net Income/(Loss)
Less: Net (loss)/income attributable to
noncontrolling interests and redeemable
noncontrolling interests
Net Income/(Loss) Attributable to NRG Energy,
Inc.
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
NRG
Energy, Inc.
(Note Issuer)
(In millions)
Eliminations (a)
Consolidated
Balance
$
7,509
$
3,222
$
— $
(219) $
10,512
5,402
565
378
415
—
6,760
—
(1)
748
(176)
5
—
4
—
(15)
(182)
566
(1)
567
—
567
2,080
581
324
192
59
3,236
—
—
(14)
(5)
36
(252)
23
(4)
(396)
(598)
(612)
7
(619)
81
(538)
42
26
—
488
30
586
193
(79)
(472)
313
(4)
(16)
9
(138)
(484)
(320)
(792)
(63)
(729)
11
(718)
(223)
—
—
—
—
(223)
—
—
4
(132)
(10)
—
(2)
—
—
(144)
(140)
62
(202)
—
(202)
7,301
1,172
702
1,095
89
10,359
193
(80)
266
—
27
(268)
34
(142)
(895)
(1,244)
(978)
5
(983)
92
(891)
—
(103)
56
(70)
(117)
$
567
$
(435) $
(774) $
(132) $
(774)
(a) All significant intercompany transactions have been eliminated in consolidation.
220
221
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2016
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
NRG Energy, Inc.
Eliminations (a)
Consolidated
Balance
ASSETS
Current Assets
Cash and cash equivalents
Funds deposited by counterparties
Restricted cash
Accounts receivable - trade
Inventory
Derivative instruments
Cash collateral posted in support of energy risk management
activities
Accounts receivable - affiliate
Current assets held-for-sale
Prepayments and other current assets
Current assets - discontinued operations
Total current assets
Net Property, Plant and Equipment
Other Assets
Investment in subsidiaries
Equity investments in affiliates
Notes receivable, less current portion
Goodwill
Intangible assets, net
Nuclear decommissioning trust fund
Derivative instruments
Deferred income taxes
Non-current assets held for sale
Other non-current assets
Non-current assets - discontinued operations
Total other assets
Total Assets
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt and capital leases
Accounts payable
Accounts payable - affiliate
Derivative instruments
Cash collateral received in support of energy risk management
activities
Accrued interest expense
Other accrued expenses and other current liabilities
Current liabilities - discontinued operations
Total current liabilities
Other Liabilities
Long-term debt and capital leases
Nuclear decommissioning reserve
Nuclear decommissioning trust liability
Postretirement and other benefit obligations
Deferred income taxes
Derivative instruments
Out-of-market contracts, net
Non-current liabilities held-for-sale
Other non-current liabilities
Other non-current liabilities - discontinued operations
Total non-current liabilities
Total Liabilities
Redeemable noncontrolling interest in subsidiaries
Stockholders' Equity
Total Liabilities and Stockholders' Equity
$
— $
2
11
734
482
962
116
307
—
76
—
2,690
4,219
1,090
(13)
—
359
592
610
144
3
—
67
—
2,852
9,761
$
— $
501
753
947
81
3
313
—
2,598
244
287
339
113
186
157
80
—
283
—
1,689
4,287
—
5,474
9,761
$
$
$
$
(a) All significant intercompany transactions have been eliminated in consolidation.
$
615
—
435
321
239
196
34
(254)
9
152
1,919
3,666
10,926
145
1,103
16
303
1,384
—
44
—
10
446
2,961
6,412
21,004
498
247
(443)
237
—
54
155
1,210
1,958
8,252
—
—
122
125
170
150
11
309
3,184
12,323
14,281
46
6,677
21,004
$
$
$
323
—
—
3
—
1
—
200
—
62
—
589
251
10,128
30
(76)
—
—
—
36
222
—
328
—
10,668
11,508
$
$
(58) $
34
(200)
—
—
123
342
—
241
7,461
—
—
275
(291)
—
—
—
74
—
7,519
7,760
—
3,748
11,508
$
— $
—
—
—
—
(92)
—
(139)
—
—
—
(231)
(27)
(11,363)
—
76
—
(3)
—
(43)
—
—
—
—
(11,333)
(11,591) $
$
76
—
(79)
(92)
—
—
—
—
(95)
—
—
—
—
—
(43)
—
—
—
—
(43)
(138)
—
(11,453)
(11,591) $
938
2
446
1,058
721
1,067
150
114
9
290
1,919
6,714
15,369
—
1,120
16
662
1,973
610
181
225
10
841
2,961
8,599
30,682
516
782
31
1,092
81
180
810
1,210
4,702
15,957
287
339
510
20
284
230
11
666
3,184
21,488
26,190
46
4,446
30,682
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2016
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
NRG Energy, Inc.
(Note Issuer)
(In millions)
Eliminations(a)
Consolidated
Balance
Cash Flows from Operating Activities
Net income/(loss)
Income from discontinued operations
Net income/(loss) from continuing operations
Adjustments to reconcile net income/(loss) to net cash provided by
operating activities:
Equity in earnings and distribution of unconsolidated affiliates
Depreciation and amortization
Provision for bad debts
Amortization of nuclear fuel
Amortization of financing costs and debt discount/premiums
Adjustment for debt extinguishment
Amortization of intangibles and out-of-market contracts
Amortization of unearned equity compensation
Net loss on sale of assets and equity method investments, net
Impairment losses
Changes in derivative instruments
Changes in deferred income taxes and liability for uncertain tax
benefits
Changes in collateral deposits in support of energy risk
management activities
Proceeds from sale of emission allowances
Changes in nuclear decommissioning trust liability
Cash (used)/provided by changes in other working capital
Cash provided by continuing operations
Cash used by discontinued operations
Net Cash Provided by Operating Activities
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.
Intercompany dividends
Acquisition of Drop Down Assets, net of cash acquired
Acquisition of businesses, net of cash acquired
Capital expenditures
Net cash proceeds from notes receivable
Proceeds from renewable energy grants
Purchases of emission allowances, net of proceeds
Investments in nuclear decommissioning trust fund securities
Proceeds from sales of nuclear decommissioning trust fund
securities
Proceeds from sale of assets, net
Investments in unconsolidated affiliates
Other
Cash (used)/provided by continuing operations
Cash provided by discontinued operations
Net Cash (Used)/Provided by Investing Activities
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.
Intercompany dividends
Payments (for)/from intercompany loans
Acquisition of Drop Down Assets, net of cash acquired
Payment of dividends to common and preferred stockholders
Net receipts from settlement of acquired derivatives that include
financing elements
Payment for preferred shares
Payments for debt extinguishment costs
Distributions from, net of contributions to, noncontrolling interest in
subsidiaries
Proceeds from issuance of common stock
Proceeds from issuance of long-term debt
Payment of debt issuance and hedging costs
Payments for short and long-term debt
Other
Cash (used)/provided by continuing operations
Cash provided by discontinued operations
Net Cash (Used)/Provided by Financing Activities
Effect of exchange rate changes on cash and cash equivalents
Change in cash from discontinued operations
Net (Decrease)/Increase in Cash and Cash Equivalents, Restricted
Cash, and Funds Deposited by Counterparties
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited
by Counterparties at Beginning of Period
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited
by Counterparties at End of Period
$
$
567
—
567
(538) $
81
(619)
(718) $
11
(729)
(202) $
—
(202)
(5)
565
41
49
—
—
39
—
—
378
(77)
(1)
437
34
41
(1,815)
253
—
253
—
—
—
—
(180)
—
—
(1)
(551)
510
—
3
27
(192)
—
(192)
—
(52)
(52)
—
—
—
—
—
—
—
—
—
(1)
(3)
(108)
—
(108)
—
—
(47)
60
52
581
7
—
34
4
128
—
—
578
145
18
(39)
—
—
417
1,306
(119)
1,187
—
—
(77)
(209)
(748)
17
36
—
—
—
56
(26)
—
(951)
297
(654)
(81)
40
(49)
—
—
6
—
—
(156)
—
1,387
(29)
(983)
(10)
125
140
265
1
318
481
569
5
26
—
—
21
138
—
10
70
16
(36)
(60)
—
—
—
1,187
648
—
648
81
12
—
—
(48)
—
—
—
—
—
17
—
8
70
—
70
—
—
101
77
(76)
—
(226)
(121)
—
1
4,140
(60)
(4,924)
—
(1,088)
—
(1,088)
—
—
(370)
693
2
—
—
—
—
—
—
—
—
—
—
—
—
—
—
200
—
—
—
(81)
(12)
77
—
—
—
—
—
—
—
—
—
—
(16)
—
(16)
81
12
—
(77)
—
—
—
—
—
—
—
—
—
—
16
—
16
—
—
—
—
$
13
$
1,050
$
323
$
— $
(891)
92
(983)
54
1,172
48
49
55
142
167
10
70
972
32
(43)
398
34
41
(11)
2,207
(119)
2,088
—
—
—
(209)
(976)
17
36
(1)
(551)
510
73
(23)
35
(1,089)
297
(792)
—
—
—
—
(76)
6
(226)
(121)
(156)
1
5,527
(89)
(5,908)
(13)
(1,055)
140
(915)
1
318
64
1,322
1,386
222
(a) All significant intercompany transactions have been eliminated in consolidation.
223
NRG ENERGY, INC. AND SUBSIDIARIES
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME
For the Year Ended December 31, 2015
For the Year Ended December 31, 2015
Net Loss
Other Comprehensive (Loss)/Income, net of
tax
Unrealized (loss)/gain on derivatives, net
Foreign currency translation adjustments, net
Available-for-sale securities, net
Defined benefit plan, net
Other comprehensive (loss)/income
Comprehensive Loss
Less: Comprehensive (loss)/income
attributable to noncontrolling interest
Comprehensive Loss Attributable to NRG
Energy, Inc.
Dividends for preferred shares
Comprehensive Loss Available for Common
Stockholders
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
NRG Energy, Inc.
(Note Issuer)
Eliminations(a)
Consolidated
Balance
$
(2,449) $
(484) $
(6,351) $
2,848
$
(6,436)
(In millions)
(8)
—
—
(22)
(30)
(2,479)
—
(2,479)
—
(16)
(7)
(1)
(15)
(39)
(523)
(42)
(481)
—
48
(4)
18
(42)
20
(6,331)
(39)
—
—
89
50
2,898
(15)
(11)
17
10
1
(6,435)
31
(62)
(73)
(6,362)
20
2,960
—
(6,362)
20
$
(2,479) $
(481) $
(6,382) $
2,960
$
(6,382)
(a) All significant intercompany transactions have been eliminated in consolidation.
Operating Revenues
Total operating revenues
Operating Costs and Expenses
Cost of operations
Depreciation and amortization
Impairment losses
Selling, general and administrative
Development costs
Total operating costs and expenses
Other income - affiliate
Gain on postretirement benefits curtailment
Operating Loss
Other (Expense)/Income
Equity in losses of consolidated subsidiaries
Equity in earnings of unconsolidated affiliates
Impairment losses on investments
Other income, net
Loss on sale of equity-method investment
Net (loss)/gain on debt extinguishment
Interest expense
Total other expense
Loss from Continuing Operations Before
Income Taxes
Income tax (benefit)/expense
Loss from Continuing Operations
Loss/(income) from Discontinued Operations, net
of income tax
Net Loss
Less: Net (loss)/income attributable to
noncontrolling interests and redeemable
noncontrolling interests
Net Loss Attributable to NRG Energy, Inc.
$
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
NRG Energy, Inc. Eliminations (a)
Consolidated
Balance
(In millions)
$
9,881
$
2,541
$
— $
(94) $
12,328
7,610
751
4,494
468
—
13,323
—
—
(3,442)
(109)
8
—
4
—
—
(14)
(111)
(3,553)
(1,104)
(2,449)
—
(2,449)
1,470
580
366
204
61
2,681
—
21
(119)
(1)
37
(25)
21
—
(9)
(366)
(343)
(462)
(93)
(369)
(115)
(484)
14
20
—
556
93
683
193
—
(490)
(2,800)
—
(31)
1
(14)
19
(557)
(3,382)
(3,872)
2,489
(6,361)
10
(6,351)
(94)
—
—
—
—
(94)
—
—
—
2,910
(9)
—
—
—
—
—
2,901
2,901
53
2,848
—
2,848
9,000
1,351
4,860
1,228
154
16,593
193
21
(4,051)
—
36
(56)
26
(14)
10
(937)
(935)
(4,986)
1,345
(6,331)
(105)
(6,436)
—
(2,449) $
(23)
(461) $
31
(6,382) $
(62)
2,910
$
(54)
(6,382)
(a) All significant intercompany transactions have been eliminated in consolidation.
224
225
SCHEDULE II. VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2017, 2016, and 2015
Allowance for doubtful accounts, deducted from
accounts receivable
Year Ended December 31, 2017
Year Ended December 31, 2016
Year Ended December 31, 2015
Income tax valuation allowance, deducted from
deferred tax assets(b)
Balance at
Beginning of
Period
Charged to
Costs and
Expenses
Charged to
Other Accounts
(In millions)
Deductions
Balance at
End of Period
$
$
29
21
21
$
56
47
62
— $
—
—
(57) (a) $
(39) (a)
(62) (a)
28
29
21
Year Ended December 31, 2017
Year Ended December 31, 2016
Year Ended December 31, 2015
$
4,116
$
3,575
265
(151) $
306
3,039
(15) $ (2,087) (c) $
235
—
271
—
1,863
4,116
3,575
(a) Represents principally net amounts charged as uncollectible.
(b)
Includes income tax valuation allowance deducted from deferred tax assets recorded as discontinued operations, which amounted to $2,087 million and
$2,194 million as of December 31, 2016 and 2015, respectively.
(c) Represents deconsolidation of GenOn due to its petition for bankruptcy on June 14, 2017.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2015
Cash Flows from Operating Activities
Net loss
(Loss)/income from discontinued operations
Net loss from continuing operations
Adjustments to reconcile net loss to net cash (used)/provided by
operating activities:
Equity in earnings and distribution of unconsolidated affiliates
Depreciation and amortization
Provision for bad debts
Amortization of nuclear fuel
Amortization of financing costs and debt discount/premiums
Adjustment for debt extinguishment
Amortization of intangibles and out-of-market contracts
Amortization of unearned equity compensation
Net loss on sale of assets and equity method investments
Gain on post retirement benefits curtailment
Impairment losses
Changes in derivative instruments
Changes in deferred income taxes and liability for uncertain tax
benefits
Changes in collateral deposits in support of energy risk
management activities
Proceeds from sale of emission allowances
Changes in nuclear decommissioning trust liability
Cash (used)/provided by changes in other working capital
Cash (used)/provided by continuing operations
Cash provided by discontinued operations
Net Cash (Used)/Provided by Operating Activities
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.
Intercompany dividends
Acquisition of Drop Down Assets, net of cash acquired
Acquisition of business, net of cash acquired
Capital expenditures
Net cash proceeds from notes receivable
Proceeds from renewable energy grants
Proceeds from emission allowances, net of purchases
Investments in nuclear decommissioning trust fund securities
Proceeds from sales of nuclear decommissioning trust fund
securities
Proceeds from sale of assets, net
Investments in unconsolidated affiliates
Other
Cash (used)/provided by continuing operations
Cash used by discontinued operations
Net Cash (Used)/Provided by Investing Activities
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.
Intercompany dividends
Payments from/(for) intercompany loans
Acquisition of Drop Down Assets, net of cash acquired
Payment of dividends to common and preferred stockholders
Net receipts from settlement of acquired derivatives that include
financing elements
Payment for treasury stock
Distributions from, net of contributions to, noncontrolling
interest in subsidiaries
Proceeds from sale of noncontrolling interests in subsidiaries
Proceeds from issuance of common stock
Proceeds from issuance of long-term debt
Payment of debt issuance and hedging costs
Payments for short and long-term debt
Other
Cash provided/(used) by continuing operations
Cash used by discontinued operations
Net Cash Provided/(Used) by Financing Activities
Effect of exchange rate changes on cash and cash equivalents
Change in cash from discontinued operations
Net Increase/(Decrease) in Cash and Cash Equivalents, Restricted
Cash, and Funds Deposited by Counterparties
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited
by Counterparties at Beginning of Period
Cash and Cash Equivalents, Restricted Cash, and Funds Deposited
by Counterparties at End of Period
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
NRG Energy, Inc.
(Note Issuer)
(In millions)
Eliminations(a)
Consolidated
Balance
$
(2,449) $
—
(2,449)
(484) $
(115)
(369)
(6,351) $
10
(6,361)
$
2,848
—
2,848
(6,436)
(105)
(6,331)
(5)
751
58
45
—
—
52
—
—
—
4,494
264
(1,092)
(323)
(24)
(2)
(8,656)
(6,887)
—
(6,887)
—
—
—
—
(316)
—
—
41
(629)
631
—
1
—
(272)
—
(272)
—
—
7,183
—
—
—
—
—
—
—
—
—
—
—
7,183
—
7,183
—
—
24
36
54
580
3
—
21
9
99
(2)
—
(21)
391
(29)
(237)
(11)
—
—
(907)
(419)
62
(357)
—
—
(698)
(31)
(654)
18
82
—
—
—
1
(357)
16
(1,623)
(259)
(1,882)
(70)
(33)
1,258
—
—
14
—
47
600
—
953
(21)
(1,116)
(22)
1,610
(55)
1,555
10
(252)
(422)
991
—
20
3
—
26
(19)
—
41
14
—
31
—
2,655
—
—
—
12,183
8,593
—
8,593
70
33
—
—
(59)
—
—
—
—
—
26
(39)
—
31
—
31
—
—
(8,441)
698
(201)
—
(437)
—
—
1
51
—
(246)
—
(8,575)
—
(8,575)
—
—
49
644
(12)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(2,836)
—
—
—
(70)
(33)
698
—
—
—
—
—
—
—
—
—
—
595
—
595
70
33
—
(698)
—
—
—
—
—
—
—
—
—
—
(595)
—
(595)
—
—
—
—
$
60
$
569
$
693
$
— $
37
1,351
64
45
47
(10)
151
39
14
(21)
4,916
235
1,326
(334)
(24)
(2)
(216)
1,287
62
1,349
—
—
—
(31)
(1,029)
18
82
41
(629)
631
27
(395)
16
(1,269)
(259)
(1,528)
—
—
—
—
(201)
14
(437)
47
600
1
1,004
(21)
(1,362)
(22)
(377)
(55)
(432)
10
(252)
(349)
1,671
1,322
(a) All significant intercompany transactions have been eliminated in consolidation.
226
227
Number
Description
Method of Filing
EXHIBIT INDEX
2.1
2.2
2.3
2.4
2.5
2.6
2.7
2.8
Third Amended Joint Plan of Reorganization of NRG Energy, Inc.,
NRG Power Marketing, Inc., NRG Capital LLC, NRG Finance
Company I LLC, and NRGenerating Holdings (No. 23) B.V.
Incorporated herein by reference to Exhibit 99.1 to the
Registrant's current report on Form 8-K filed on
November 19, 2003.
First Amended Joint Plan of Reorganization of NRG Northeast
Generating LLC (and certain of its subsidiaries), NRG South Central
Generating (and certain of its subsidiaries) and Berrians I Gas Turbine
Power LLC.
Incorporated herein by reference to Exhibit 99.2 to the
Registrant's current report on Form 8-K filed on
November 19, 2003.
Acquisition Agreement, dated as of September 30, 2005, by and
among NRG Energy, Inc., Texas Genco LLC and the Direct and
Indirect Owners of Texas Genco LLC.
Incorporated herein by reference to Exhibit 2.1 to the
Registrant's current report on Form 8-K filed on October
3, 2005.
Purchase and Sale Agreement by and between Denali Merger Sub Inc.
and NRG Energy, Inc. dated as of August 13, 2010.
Incorporated herein by reference to Exhibit 99.2 to the
Registrant's current report on Form 8-K filed on
August 13, 2010.
Agreement and Plan of Merger, dated as of July 20, 2012, by and
among NRG Energy, Inc., Plus Merger Corporation and GenOn
Energy, Inc.
Incorporated herein by reference to Exhibit 2.1 to the
Registrant's current report on Form 8-K filed on July 23,
2012.
Plan Sponsor Agreement, dated October 18, 2013, by and among NRG
Energy, Inc., NRG Energy Holdings, Inc., Edison Mission Energy,
certain of Edison Mission Energy’s debtor subsidiaries, the Official
Committee of Unsecured Creditors of Edison Mission Energy and its
affiliated debtors, the PoJo Parties (as defined therein) and the
proponent noteholders thereto.
Incorporated herein by reference to Exhibit 2.1 to
Amendment No. 1 to the Registrant’s current report on
Form 8-K filed on October 21, 2013.
Asset Purchase Agreement, dated October 18, 2013, by and among
NRG Energy, Inc., Edison Mission Energy and NRG Energy Holdings
Inc.
Incorporated herein by reference to Exhibit 2.2 to
Amendment No. 1 to the Registrant’s current report on
Form 8-K filed on October 21, 2013.
Third Amended Joint Plan of Reorganization of GenOn Energy, Inc.
and its Debtor Affiliates.
Incorporated herein by reference to Exhibit 2.1 to the
Registrant's current report on Form 8-K filed on
December 18, 2017.
2.9†^
2.10^
Purchase and Sale Agreement, dated as of February 6, 2018, by and
among NRG Energy, Inc. and NRG Repowering Holdings LLC, and
GIP III Zephyr Acquisition Partners, L.P.
Purchase and Sale Agreement, dated as of February 6, 2018, by and
between NRG Energy, Inc., NRG South Central Generating LLC, and
Cleco Energy LLC.
Filed herewith.
Filed herewith.
3.1
3.2
3.3
3.4
3.5
3.6
3.7
4.1
Amended and Restated Certificate of Incorporation.
Certificate of Amendment to Amended and Restated Certificate of
Incorporation.
Fourth Amended and Restated By-Laws.
Certificate of Designations relating to the Series 1 Exchangeable
Limited Liability Company Preferred Interests of NRG Common
Stock Finance I LLC, as filed with the Secretary of State of Delaware
on August 4, 2006.
Certificate of Amendment to Certificate of Designations relating to
the Series 1 Exchangeable Limited Liability Company Preferred
Interests of NRG Common Stock Finance I LLC, as filed with the
Secretary of State of Delaware on February 27, 2008.
Second Certificate of Amendment to Certificate of Designations
relating to the Series 1 Exchangeable Limited Liability Company
Preferred Interests of NRG Common Stock Finance I LLC, as filed
with the Secretary of State of Delaware on August 8, 2008.
Incorporated herein by reference to Exhibit 3.1 to the
Registrant's quarterly report on Form 10-Q filed on May
3, 2012.
Incorporated herein by reference to Exhibit 3.1 to the
Registrant's current report on Form 8-K filed on
December 14, 2012.
Incorporated herein by reference to Exhibit 3.1 to the
Registrant's current report on Form 8-K filed on
February 13, 2017.
Incorporated herein by reference to Exhibit 10.7 to the
Registrant's current report on Form 8-K filed on August
10, 2006.
Incorporated herein by reference to Exhibit 3.1 to the
Registrant's quarterly report on Form 10-Q filed on May
1, 2008.
Incorporated herein by reference to Exhibit 3.1 to the
Registrant's quarterly report on Form 10-Q filed on
October 30, 2008.
Certificate of Designations of 2.822% Convertible Perpetual
Preferred Stock, as filed with the Secretary of State of the State of
Delaware on December 30, 2014.
Incorporated herein by reference to Exhibit 3.1 to the
Registrant's current report on Form 8-K filed on
December 30, 2014.
Supplemental Indenture, dated as of December 30, 2005, among NRG
Energy, Inc., the subsidiary guarantors named on Schedule A thereto
and Law Debenture Trust Company of New York, as trustee.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's current report on Form 8-K filed on January
4, 2006.
4.2
4.3
4.4
4.5
4.6
4.7
4.8
Amended and Restated Common Agreement among XL Capital
Assurance Inc., Goldman Sachs Mitsui Marine Derivative Products,
L.P., Law Debenture Trust Company of New York, as Trustee, The
Bank of New York, as Collateral Agent, NRG Peaker Finance
Company LLC and each Project Company Party thereto, dated as of
January 6, 2004, together with Annex A to the Common Agreement.
Amended and Restated Security Deposit Agreement among NRG
Peaker Finance Company, LLC and each Project Company party
thereto, and the Bank of New York, as Collateral Agent and Depositary
Agent, dated as of January 6, 2004.
NRG Parent Agreement by NRG Energy, Inc. in favor of the Bank of
New York, as Collateral Agent, dated as of January 6, 2004.
Indenture dated June 18, 2002, between NRG Peaker Finance
Company LLC, as Issuer, Bayou Cove Peaking Power LLC, Big Cajun
I Peaking Power LLC, NRG Rockford LLC, NRG Rockford II LLC
and Sterlington Power LLC, as Guarantors, XL Capital Assurance Inc.,
as Insurer, and Law Debenture Trust Company, as Successor Trustee
to the Bank of New York.
Specimen of Certificate representing common stock of NRG Energy,
Inc.
Indenture, dated February 2, 2006, among NRG Energy, Inc. and Law
Debenture Trust Company of New York.
Thirty-Sixth Supplemental Indenture, dated August 20, 2010, among
NRG Energy, Inc., the guarantors named therein and Law Debenture
Trust Company of New York as Trustee, re: NRG Energy, Inc.'s 8.25%
Senior Notes due 2020.
4.9
Form of 8.25% Senior Note due 2020.
4.10
4.11
4.12
Registration Rights Agreement, dated August 20, 2010, among NRG
Energy, Inc., the guarantors named therein and Citigroup Global
Markets Inc., Banc of America Securities LLC and Deutsche Bank
Securities Inc., as representatives of the several initial purchasers.
Forty-First Supplemental Indenture, dated as of December 15, 2010,
among NRG Energy, Inc., the existing guarantors named therein, the
guaranteeing subsidiaries named therein and Law Debenture Trust
Company of New York as Trustee, re: NRG Energy, Inc.'s 8.25%
Senior Notes due 2020.
Forty-Second Supplemental Indenture, dated January 26, 2011,
among NRG Energy, Inc., the existing guarantors named therein, the
guaranteeing subsidiaries named therein and Law Debenture Trust
Company of New York as Trustee, re: NRG Energy, Inc.’s 7.625%
Senior Notes due 2018.
4.13
Form of 7.625% Senior Note due 2018.
Incorporated herein by reference to Exhibit 4.9 to the
Registrant's annual report on Form 10-K filed on
March 16, 2004.
Incorporated herein by reference to Exhibit 4.10 to the
Registrant's annual report on Form 10-K filed on
March 16, 2004.
Incorporated herein by reference to Exhibit 4.11 to the
Registrant's annual report on Form 10-K filed on
March 16, 2004.
Incorporated herein by reference to Exhibit 4.23 to the
Registrant's annual report on Form 10-K filed on
March 31, 2003.
Incorporated herein by reference to Exhibit 4.3 to the
Registrant's quarterly report on Form 10-Q filed on
August 4, 2006.
Incorporated herein by reference to Exhibit 4.1 to the
Registrant's current report on Form 8-K filed on
February 6, 2006.
Incorporated herein by reference to Exhibit 4.1 to the
Registrant's current report on Form 8-K filed on
August 20, 2010.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant's current report on Form 8-K filed on
August 20, 2010.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's current report on Form 8-K filed on
August 20, 2010.
Incorporated herein by reference to Exhibit 4.5 to the
Registrant's current report on Form 8-K filed on
December 16, 2010.
Incorporated herein by reference to Exhibit 4.1 to the
Registrant's current report on Form 8-K filed on January
28, 2011.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant's current report on Form 8-K filed on January
28, 2011.
4.14
4.15
4.16
4.17
Registration Rights Agreement, dated January 26, 2011, among NRG
Energy, Inc., the guarantors named therein and J.P. Morgan
Securities LLC, as initial purchaser.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's current report on Form 8-K filed on January
28, 2011.
Forty-Eighth Supplemental Indenture, dated May 20, 2011, among
NRG Energy, Inc., the existing guarantors named therein, the
guaranteeing subsidiaries named therein and Law Debenture Trust
Company of New York as Trustee, re: NRG Energy, Inc.’s 8.25%
Senior Notes due 2020.
Forty-Ninth Supplemental Indenture, dated May 20, 2011, among
NRG Energy, Inc., the existing guarantors named therein, the
guaranteeing subsidiaries named therein and Law Debenture Trust
Company of New York as Trustee, re: NRG Energy, Inc.’s 7.625%
Senior Notes due 2018.
Fifty-First Supplemental Indenture, dated May 24, 2011, among NRG
Energy, Inc., the existing guarantors named therein, the guaranteeing
subsidiaries named therein and Law Debenture Trust Company of New
York as Trustee, re: NRG Energy, Inc.’s 7.875% Senior Notes due
2021.
Incorporated herein by reference to Exhibit 4.4 to the
Registrant's current report on Form 8-K filed on
May 25, 2011.
Incorporated herein by reference to Exhibit 4.5 to the
Registrant's current report on Form 8-K filed on
May 25, 2011.
Incorporated herein by reference to Exhibit 4.3 to the
Registrant's current report on Form 8-K filed on
May 25, 2011.
228
229
4.18
Form of 7.875% Senior Note due 2021.
4.19
4.20
4.21
4.22
4.23
4.24
4.25
4.26
4.27
4.28
4.29
Registration Rights Agreement, dated May 24, 2011, among NRG
Energy, Inc., the guarantors named therein and Morgan Stanley & Co.
Incorporated, Merrill Lynch, Pierce, Fenner & Smith Incorporated,
Barclays Capital Inc., Citigroup Global Markets Inc., Credit Suisse
Securities (USA) LLC, Deutsche Bank Securities Inc., Goldman,
Sachs & Co., J.P. Morgan Securities LLC and RBS Securities Inc., as
representatives of the initial purchasers.
Fifty-Fourth Supplemental Indenture, dated November 8, 2011,
among NRG Energy, Inc., the existing guarantors named therein, the
guaranteeing subsidiaries named therein and Law Debenture Trust
Company of New York as Trustee, re: NRG Energy, Inc.’s 8.25%
Senior Notes due 2020.
Fifty-Fifth Supplemental Indenture, dated November 8, 2011, among
NRG Energy, Inc., the existing guarantors named therein, the
guaranteeing subsidiaries named therein and Law Debenture Trust
Company of New York as Trustee, re: NRG Energy, Inc.’s 7.625%
Senior Notes due 2018.
Fifty-Seventh Supplemental Indenture, dated November 8, 2011,
among NRG Energy, Inc., the existing guarantors named therein, the
guaranteeing subsidiaries named therein and Law Debenture Trust
Company of New York as Trustee, re: NRG Energy, Inc.’s 7.875%
Senior Notes due 2021.
Sixtieth Supplemental Indenture, dated April 5, 2012, among NRG
Energy, Inc., the existing guarantors named therein, the guaranteeing
subsidiaries named therein and Law Debenture Trust Company of New
York as Trustee, re: NRG Energy, Inc.’s 8.25% Senior Notes due 2020.
Sixty-First Supplemental Indenture, dated April 5, 2012, among NRG
Energy, Inc., the existing guarantors named therein, the guaranteeing
subsidiaries named therein and Law Debenture Trust Company of New
York as Trustee, re: NRG Energy, Inc.’s 7.625% Senior Notes due
2018.
Sixty-Third Supplemental Indenture, dated April 5, 2012, among NRG
Energy, Inc., the existing guarantors named therein, the guaranteeing
subsidiaries named therein and Law Debenture Trust Company of New
York as Trustee, re: NRG Energy, Inc.’s 7.875% Senior Notes due
2021.
Sixty-Sixth Supplemental Indenture, dated May 9, 2012, among NRG
Energy, Inc., the existing guarantors named therein, the guaranteeing
subsidiaries named therein and Law Debenture Trust Company of New
York as Trustee, re: NRG Energy, Inc.’s 8.25% Senior Notes due 2020.
Sixty-Seventh Supplemental Indenture, dated May 9, 2012, among
NRG Energy, Inc., the existing guarantors named therein, the
guaranteeing subsidiaries named therein and Law Debenture Trust
Company of New York as Trustee, re: NRG Energy, Inc.’s 7.625%
Senior Notes due 2018.
Sixty-Ninth Supplemental Indenture, dated May 9, 2012, among NRG
Energy, Inc., the existing guarantors named therein, the guaranteeing
subsidiaries named therein and Law Debenture Trust Company of New
York as Trustee, re: NRG Energy, Inc.’s 7.875% Senior Notes due
2021.
Seventieth Supplemental Indenture, dated September 24, 2012, among
NRG Energy, Inc., the existing guarantors named therein, the
guaranteeing subsidiaries named therein and Law Debenture Trust
Company of New York as Trustee, re: NRG Energy, Inc.’s 6.625%
Senior Notes due 2023.
4.30
Form of 6.625% Senior Note due 2023.
4.31
Seventy-Second Supplemental Indenture, dated October 9, 2012,
among NRG Energy, Inc., the existing guarantors named therein, the
guaranteeing subsidiaries named therein and Law Debenture Trust
Company of New York as Trustee, re: NRG Energy, Inc.’s 8.25%
Senior Notes due 2020.
Incorporated herein by reference to Exhibit 4.4 to the
Registrant's current report on Form 8-K filed on
May 25, 2011.
Incorporated herein by reference to Exhibit 4.5 to the
Registrant's current report on Form 8-K filed on
May 25, 2011.
Incorporated herein by reference to Exhibit 4.3 to the
Registrant's current report on Form 8-K filed on
November 8, 2011.
Incorporated herein by reference to Exhibit 4.4 to the
Registrant's current report on Form 8-K filed on
November 8, 2011.
Incorporated herein by reference to Exhibit 4.6 to the
Registrant's current report on Form 8-K filed on
November 8, 2011.
Incorporated herein by reference to Exhibit 4.3 to the
Registrant's current report on Form 8-K filed on April
6, 2012.
Incorporated herein by reference to Exhibit 4.4 to the
Registrant's current report on Form 8-K filed on April
6, 2012.
Incorporated herein by reference to Exhibit 4.6 to the
Registrant's current report on Form 8-K filed on April
6, 2012.
Incorporated herein by reference to Exhibit 4.3 to the
Registrant's current report on Form 8-K filed on May
11, 2012.
Incorporated herein by reference to Exhibit 4.4 to the
Registrant's current report on Form 8-K filed on May
11, 2012.
Incorporated herein by reference to Exhibit 4.6 to the
Registrant's current report on Form 8-K filed on May
11, 2012.
Incorporated herein by reference to Exhibit 4.1 to the
Registrant's current report on Form 8-K filed on
September 24, 2012.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant's current report on Form 8-K filed on
September 24, 2012.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant's current report on Form 8-K filed on October
12, 2012.
4.32
4.33
4.34
4.35
4.36
4.37
4.38
4.39
4.40
4.41
4.42
4.43
4.44
4.45
4.46
4.47
4.48
Seventy-Third Supplemental Indenture, dated October 9, 2012, among
NRG Energy, Inc., the existing guarantors named therein, the
guaranteeing subsidiaries named therein and Law Debenture Trust
Company of New York as Trustee, re: NRG Energy, Inc.’s 7.625%
Senior Notes due 2018.
Seventy-Fifth Supplemental Indenture, dated October 9, 2012, among
NRG Energy, Inc., the existing guarantors named therein, the
guaranteeing subsidiaries named therein and Law Debenture Trust
Company of New York as Trustee, re: NRG Energy, Inc.’s 7.875%
Senior Notes due 2021.
Seventy-Sixth Supplemental Indenture, dated October 9, 2012, among
NRG Energy, Inc., the existing guarantors named therein, the
guaranteeing subsidiaries named therein and Law Debenture Trust
Company of New York as Trustee, re: NRG Energy, Inc.’s 6.625%
Senior Notes due 2023.
Senior Indenture, dated December 22, 2004, between Reliant Energy,
Inc. and Wilmington Trust Company.
Fourth Supplemental Indenture, dated June 13, 2007, among Reliant
Energy, Inc., the Guarantors listed therein and Wilmington Trust
Company as Trustee, re: GenOn Energy, Inc.’s 7.625% Senior Notes
due 2014.
Fifth Supplemental Indenture, dated June 13, 2007, among Reliant
Energy, Inc., the Guarantors listed therein and Wilmington Trust
Company as Trustee, re: GenOn Energy, Inc.’s 7.875% Senior Notes
due 2017.
Indenture, dated May 1, 2001, between Mirant Americas Generation,
Inc. and Bankers Trust Company as Trustee.
Incorporated herein by reference to Exhibit 4.3 to the
Registrant's current report on Form 8-K filed on October
12, 2012.
Incorporated herein by reference to Exhibit 4.5 to the
Registrant's current report on Form 8-K filed on October
12, 2012.
Incorporated herein by reference to Exhibit 4.6 to the
Registrant's current report on Form 8-K filed on October
12, 2012.
Incorporated herein by reference to Exhibit 4.1 to
GenOn Energy, Inc.’s current report on Form 8-K filed
on December 27, 2004.
Incorporated herein by reference to Exhibit 4.1 to
GenOn Energy Inc.'s current report on Form 8-K filed
on June 15, 2007.
Incorporated herein by reference to Exhibit 4.2 to
GenOn Energy Inc.'s current report on Form 8-K filed
June 15, 2007.
Incorporated herein by reference to Exhibit 4.1 to Mirant
Americas Generation, Inc.'s Registration Statement on
Form S-4 filed on June 18, 2001.
Third Supplemental Indenture, dated May 1, 2001, between Mirant
Americas Generation, Inc. and Bankers Trust Company as Trustee, re:
GenOn Americas Generation, LLC’s 9.125% Senior Notes due 2031.
Incorporated herein by reference to Exhibit 4.4 to Mirant
Americas Generation, Inc.'s Registration Statement on
Form S-4 filed on June 18, 2001.
Fifth Supplemental Indenture, dated October 9, 2001, between Mirant
Americas Generation, Inc. and Bankers Trust Company as Trustee, re:
GenOn Americas Generation, LLC’s 8.5% Senior Notes due 2021.
Incorporated herein by reference to Exhibit 4.6 to Mirant
Americas Generation, Inc.'s Registration Statement on
Form S-4/A filed on May 7, 2002.
Sixth Supplemental Indenture, dated November 1, 2001, between
Mirant Americas Generation LLC and Bankers Trust Company, re:
Indenture, dated May 1, 2001.
Incorporated herein by reference to Exhibit 4.6 to Mirant
Corporation's annual report on Form 10-K filed on
February 27, 2009.
Seventh Supplemental Indenture, dated January 3, 2006, between
Mirant Americas Generation LLC and Wells Fargo Bank National
Association (as successor to Bankers Trust Company), re: Indenture,
dated May 1, 2001.
Incorporated herein by reference to Exhibit 4.1 to Mirant
Americas Generation, LLC's quarterly report on Form
10-Q filed on May 14, 2007.
Senior Notes Indenture, dated October 4, 2010, by GenOn Escrow
Corp. and Wilmington Trust Company as trustee, re: GenOn Energy,
Inc.’s 9.5% Senior Notes due 2018 and 9.875% Senior Notes due 2020.
Incorporated by reference to Exhibit 4.4 to Mirant
Corporation's quarterly report on Form 10-Q filed on
November 5, 2010.
Supplemental Indenture, dated December 3, 2010, by and among
GenOn Energy, Inc., GenOn Escrow Corp. and Wilmington Trust
Company as trustee, re: GenOn Energy, Inc.’s 9.5% Senior Notes due
2018 and 9.875% Senior Notes due 2020.
Seventy-Eighth Supplemental Indenture, dated as of January 3, 2013,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as trustee, re: NRG Energy,
Inc.’s 8.25% Senior Notes due 2020.
Seventy-Ninth Supplemental Indenture, dated as of January 3, 2013,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as trustee, re: NRG Energy,
Inc.’s 7.625% Senior Notes due 2018.
Eighty-First Supplemental Indenture, dated as of January 3, 2013,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as trustee, re: NRG Energy,
Inc.’s 7.875% Senior Notes due 2021.
Eighty-Second Supplemental Indenture, dated as of January 3, 2013,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as trustee, re: NRG Energy,
Inc.’s 6.625% Senior Notes due 2023.
Incorporated by reference to Exhibit 4.2 to GenOn
Energy Inc.'s current report on Form 8-K filed on
December 7, 2010.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant’s current report on Form 8-K filed on January
9, 2013.
Incorporated herein by reference to Exhibit 4.3 to the
Registrant’s current report on Form 8-K filed on January
9, 2013.
Incorporated herein by reference to Exhibit 4.5 to the
Registrant’s current report on Form 8-K filed on January
9, 2013.
Incorporated herein by reference to Exhibit 4.6 to the
Registrant’s current report on Form 8-K filed on January
9, 2013.
230
231
4.49
4.50
4.51
4.52
4.53
4.54
4.55
4.56
4.57
4.58
4.59
4.60
4.61
4.62
4.63
4.64
4.65
Eighty-Fourth Supplemental Indenture, dated as of March 13, 2013,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as trustee, re: NRG Energy,
Inc.’s 8.25% Senior Notes due 2020.
Eighty-Fifth Supplemental Indenture, dated as of March 13, 2013,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as trustee, re: NRG Energy,
Inc.’s 7.625% Senior Notes due 2018.
Eighty-Seventh Supplemental Indenture, dated as of March 13, 2013,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as trustee, re: NRG Energy,
Inc.’s 7.875% Senior Notes due 2021.
Eighty-Eighth Supplemental Indenture, dated as of March 13, 2013,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as trustee, re: NRG Energy,
Inc.’s 6.625% Senior Notes due 2023.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant’s current report on Form 8-K filed on March
13, 2013.
Incorporated herein by reference to Exhibit 4.3 to the
Registrant’s current report on Form 8-K filed on March
13, 2013.
Incorporated herein by reference to Exhibit 4.5 to the
Registrant’s current report on Form 8-K filed on March
13, 2013.
Incorporated herein by reference to Exhibit 4.6 to the
Registrant’s current report on Form 8-K filed on March
13, 2013.
Eighty-Ninth Supplemental Indenture, dated as of March 13, 2013,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York.
Incorporated herein by reference to Exhibit 4.7 to the
Registrant’s current report on Form 8-K filed on March
13, 2013.
Ninety-First Supplemental Indenture, dated as of May 2, 2013, among
NRG Energy, Inc., the guarantors named therein and Law Debenture
Trust Company of New York as trustee, re: NRG Energy, Inc.’s 8.25%
Senior Notes due 2020.
Ninety-Second Supplemental Indenture, dated as of May 2, 2013,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as trustee, re: NRG Energy,
Inc.’s 7.625% Senior Notes due 2018.
Ninety-Fourth Supplemental Indenture, dated as of May 2, 2013,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as trustee, re: NRG Energy,
Inc.’s 7.875% Senior Notes due 2021.
Ninety-Fifth Supplemental Indenture, dated as of May 2, 2013, among
NRG Energy, Inc., the guarantors named therein and Law Debenture
Trust Company of New York as trustee, re: NRG Energy, Inc.’s 6.625%
Senior Notes due 2023.
Ninety-Seventh Supplemental Indenture, dated as of September 4,
2013, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York as trustee, re: NRG
Energy, Inc.’s 8.25% Senior Notes due 2020.
Ninety-Eighth Supplemental Indenture, dated as of September 4, 2013,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as trustee, re: NRG Energy,
Inc.’s 7.625% Senior Notes due 2018
One Hundredth Supplemental Indenture, dated as of September 4,
2013, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York as trustee, re: NRG
Energy, Inc.’s 7.875% Senior Notes due 2021.
One Hundred-First Supplemental Indenture, dated as of September 4,
2013, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York as trustee, re: NRG
Energy, Inc.’s 6.625% Senior Notes due 2023.
One Hundred-Third Supplemental Indenture, dated as of October 7,
2013, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York as trustee, re: NRG
Energy, Inc.’s 8.25% Senior Notes due 2020.
One Hundred-Fourth Supplemental Indenture, dated as of October 7,
2013, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York as trustee, re: NRG
Energy, Inc.’s 7.625% Senior Notes due 2018.
One Hundred-Sixth Supplemental Indenture, dated as of October 7,
2013, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York as trustee, re: NRG
Energy, Inc.’s 7.875% Senior Notes due 2021.
One Hundred-Seventh Supplemental Indenture, dated as of October
7, 2013, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York as trustee, re: NRG
Energy, Inc.’s 6.625% Senior Notes due 2023.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant’s current report on Form 8-K filed on May 3,
2013.
Incorporated herein by reference to Exhibit 4.3 to the
Registrant’s current report on Form 8-K filed on May 3,
2013.
Incorporated herein by reference to Exhibit 4.5 to the
Registrant’s current report on Form 8-K filed on May 3,
2013.
Incorporated herein by reference to Exhibit 4.6 to the
Registrant’s current report on Form 8-K filed on May 3,
2013.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant’s current report on Form 8-K filed on
September 6, 2013.
Incorporated herein by reference to Exhibit 4.3 to the
Registrant’s current report on Form 8-K filed on
September 6, 2013.
Incorporated herein by reference to Exhibit 4.5 to the
Registrant’s current report on Form 8-K filed on
September 6, 2013.
Incorporated herein by reference to Exhibit 4.6 to the
Registrant’s current report on Form 8-K filed on
September 6, 2013.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant’s current report on Form 8-K filed on October
8, 2013.
Incorporated herein by reference to Exhibit 4.3 to the
Registrant’s current report on Form 8-K filed on October
8, 2013.
Incorporated herein by reference to Exhibit 4.5 to the
Registrant’s current report on Form 8-K filed on October
8, 2013.
Incorporated herein by reference to Exhibit 4.6 to the
Registrant’s current report on Form 8-K filed on October
8, 2013.
4.66
4.67
One Hundred-Eighth Supplemental
Indenture, dated as of
November 13, 2013, among NRG Energy, Inc., the guarantors named
therein and Law Debenture Trust Company of New York as trustee,
re: NRG Energy, Inc.’s 8.5% Senior Notes due 2019, 8.25% Senior
Notes due 2020, 7.625% Senior Notes due 2018, 7.625% Senior Notes
due 2019, 7.875% Senior Notes due 2021 and 6.625% Senior Notes
due 2023.
One Hundred-Ninth Supplemental Indenture, dated as of January 27,
2014, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York as Trustee, re: NRG
Energy's 6.25% Senior Notes due 2022.
4.68
Form of 6.25% Senior Note due 2022.
Registration Rights Agreement, dated January 27, 2014, among NRG
Energy, Inc., the guarantors named therein and Barclays Capital Inc.,
Deutsche Bank Securities Inc., Goldman, Sachs & Co., Morgan
Stanley & Co. LLC, Credit Agricole Securities (USA) Inc., Natixis
Securities Americas LLC and RBC Capital Markets, LLC, as initial
purchasers.
One Hundred-Tenth Supplemental Indenture, dated as of March 24,
2014, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York as trustee, re: NRG
Energy, Inc.'s 8.5% Senior Notes due 2019, 8.25% Senior Notes due
2020, 7.625% Senior Notes due 2018, 7.625% Senior Notes due 2019,
7.875% Senior Notes due 2021, 6.625% Senior Notes due 2023 and
6.25% Senior Notes due 2022.
Incorporated herein by reference to Exhibit 4.1 to the
Registrant’s current report on Form 8-K filed on
November 13, 2013.
Incorporated herein by reference to Exhibit 4.1 to the
Company's Current Report on Form 8-K filed on
January 27, 2014.
Incorporated herein by reference to Exhibit 4.2 to the
Company's Current Report on Form 8-K filed on
January 27, 2014.
Incorporated herein by reference to Exhibit 4.3 to the
Company's Current Report on Form 8-K filed on
January 27, 2014.
Incorporated herein by reference to Exhibit 4.1 to the
Company's Current Report on Form 8-K filed on March
28, 2014.
Indenture, dated as of April 21, 2014, among NRG Energy, Inc., the
guarantors named therein and Law Debenture Trust Company of New
York as Trustee, re: NRG Energy, Inc.'s 6.25% Senior Notes due 2024.
Incorporated herein by reference to Exhibit 4.1 to the
Company's Current Report on Form 8-K filed on April
21, 2014.
4.72
Form of 6.25% Senior Note due 2024.
Registration Rights Agreement, dated April 21, 2014, among NRG
Energy, Inc., the guarantors named therein and Citigroup Global
Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated,
Credit Suisse Securities (USA), Inc., J.P. Morgan Securities LLC,
Mitsubishi UFJ Securities (USA), Inc., SMBC Nikko Securities
America, Inc. and RBS Securities Inc.
One Hundred-Eleventh Supplemental Indenture, dated as of April 28,
2014, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York as trustee, re: NRG
Energy, Inc.'s 8.5% Senior Notes due 2019, 8.25% Senior Notes due
2020, 7.625% Senior Notes due 2018, 7.625% Senior Notes due 2019,
7.875% Senior Notes due 2021, 6.625% Senior Notes due 2023 and
6.25% Senior Notes due 2022.
First Supplemental Indenture, dated as of May 2, 2014, among NRG
Energy, Inc., the guarantors named therein and Law Debenture Trust
Company of New York as trustee, re: NRG Energy, Inc.'s 6.25% Senior
Notes due 2024.
Incorporated herein by reference to Exhibit 4.2 to the
Company's Current Report on Form 8-K filed on April
21, 2014.
Incorporated herein by reference to Exhibit 4.3 to the
Company's Current Report on Form 8-K filed on April
21, 2014.
Incorporated herein by reference to Exhibit 4.1 to the
Company's Current Report on Form 8-K filed on May
2, 2014.
Incorporated herein by reference to Exhibit 4.2 to the
Company's Current Report on Form 8-K filed on May
2, 2014.
One Hundred-Twelfth Supplemental Indenture, dated as of October 3,
2014, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York.
Incorporated herein by reference to Exhibit 4.1 to the
Company's Current Report on Form 8-K filed on
October 3, 2014.
Second Supplemental Indenture, dated as of October 3, 2014, among
NRG Energy, Inc., the guarantors named therein and Law Debenture
Trust Company of New York as trustee, re: NRG Energy, Inc.'s 6.25%
Senior Notes due 2024.
One Hundred-Thirteenth Supplemental Indenture, dated as of
November 12, 2014, among NRG Energy, Inc., the guarantors named
therein and Law Debenture Trust Company of New York as trustee,
re: NRG Energy, Inc.'s 8.25% Senior Notes due 2020, 7.625% Senior
Notes due 2018, 7.875% Senior Notes due 2021, 6.625% Senior Notes
due 2023 and 6.25% Senior Notes due 2022.
Incorporated herein by reference to Exhibit 4.2 to the
Company's Current Report on Form 8-K filed on
October 3, 2014.
Incorporated herein by reference to Exhibit 4.1 to the
Company's Current Report on Form 8-K filed on
November 14, 2014.
Third Supplemental Indenture, dated as of November 12, 2014, among
NRG Energy, Inc., the guarantors named therein and Law Debenture
Trust Company of New York.
Incorporated herein by reference to Exhibit 4.2 to the
Company's Current Report on Form 8-K filed on
November 14, 2014.
4.69
4.70
4.71
4.73
4.74
4.75
4.76
4.77
4.78
4.79
232
233
Incorporated herein by reference to Exhibit 4.1 to the
Registrant's current report on Form 8-K filed on
November 25, 2014.
4.97
Third Supplemental Indenture, dated August 2, 2016, among NRG
Energy, Inc., the guarantors named therein and Law Debenture Trust
Company of New York.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant's Current Report on Form 8-K, filed on
August 3, 2016.
4.80
4.81
4.82
4.83
4.84
4.85
4.86
4.87
4.88
4.89
4.90
4.91
4.93
4.94
4.95
4.96
One Hundred-Fourteenth Supplemental Indenture, dated as of
November 24, 2014, among NRG Energy, Inc., the guarantors named
therein and Law Debenture Trust Company of New York, as trustee,
re: NRG Energy, Inc.'s 8.25% Senior Notes due 2020, 7.625% Senior
Notes due 2018, 7.875% Senior Notes due 2021, 6.625% Senior Notes
due 2023 and 6.25% Senior Notes due 2022.
Fourth Supplemental Indenture, dated as of November 24, 2014,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York, as trustee, re: NRG
Energy, Inc.'s 6.25% Senior Notes due 2024.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant's current report on Form 8-K filed on
November 25, 2014.
One Hundred-Fifteenth Supplemental Indenture, dated as of April 8,
2015, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York.
Incorporated herein by reference to Exhibit 4.1 to the
Company's current report on Form 8-K filed on April 9,
2015.
Fifth Supplemental Indenture, dated as of April 8, 2015, among NRG
Energy, Inc., the guarantors named therein and Law Debenture Trust
Company of New York.
Incorporated herein by reference to Exhibit 4.2 to the
Company's current report on Form 8-K filed on April 9,
2015.
One Hundred-Sixteenth Supplemental Indenture, dated as of April 29,
2015, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York.
Incorporated herein by reference to Exhibit 4.1 to the
Company's current report on Form 8-K filed on April
30, 2015.
Sixth Supplemental Indenture, dated as of April 29, 2015, among NRG
Energy, Inc., the guarantors named therein and Law Debenture Trust
Company of New York.
Incorporated herein by reference to Exhibit 4.2 to the
Company's current report on Form 8-K filed on April
30, 2015.
One Hundred-Seventeenth Supplemental Indenture, dated as of May
22, 2015, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York.
Incorporated herein by reference to Exhibit 4.1 to the
Company's current report on Form 8-K filed on May 22,
2015.
Seventh Supplemental Indenture, dated as of May 22, 2015, among
NRG Energy, Inc., the guarantors named therein and Law Debenture
Trust Company of New York.
Incorporated herein by reference to Exhibit 4.2 to the
Company's current report on Form 8-K filed on May 22,
2015.
One Hundred-Eighteenth Supplemental Indenture, dated as of October
28, 2015, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York.
Incorporated herein by reference to Exhibit 4.1 to the
Company's current report on Form 8-K filed on
November 2, 2015.
Eighth Supplemental Indenture, dated as of October 28, 2015, among
NRG Energy, Inc., the guarantors named therein and Law Debenture
Trust Company of New York.
Incorporated herein by reference to Exhibit 4.2 to the
Company's current report on Form 8-K filed on
November 2, 2015.
Indenture, dated May 23, 2016, between NRG Energy, Inc. and Law
Debenture Trust Company of New York.
Incorporated herein by reference to Exhibit 4.1 to the
Registrant's Current Report on Form 8-K, filed on May
23, 2016.
Supplemental Indenture, dated May 23, 2016, among NRG Energy,
Inc., the guarantors named therein and Law Debenture Trust Company
of New York.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant's Current Report on Form 8-K, filed on May
23, 2016.
4.92
Form of 7.250% Senior Note due 2026.
Registration Rights Agreement, dated May 23, 2016, among NRG
Energy, Inc., the guarantors named therein and Deutsche Bank
Securities Inc., as representative to the initial purchasers listed in
Schedule I thereto.
Incorporated herein by reference to Exhibit 4.3 to the
Registrant's Current Report on Form 8-K, filed on May
23, 2016.
Incorporated herein by reference to Exhibit 4.4 to the
Registrant's Current Report on Form 8-K, filed on May
23, 2016.
One Hundred-Nineteenth Supplemental Indenture, dated as of July 19,
2016, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York.
Incorporated herein by reference to Exhibit 4.1 to the
Registrant's Current Report on Form 8-K, filed on July
25, 2016.
Ninth Supplemental Indenture, dated as of July 19, 2016, among NRG
Energy, Inc., the guarantors named therein and Law Debenture Trust
Company of New York.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant's Current Report on Form 8-K, filed on July
25, 2016.
Second Supplemental Indenture, dated as of July 19, 2016, among
NRG Energy, Inc., the guarantors named therein and Law Debenture
Trust Company of New York.
Incorporated herein by reference to Exhibit 4.3 to the
Registrant's Current Report on Form 8-K, filed on July
25, 2016.
4.98
Form of 6.625% Senior Note due 2027.
Incorporated herein by reference to Exhibit 4.3 to the
Registrant's Current Report on Form 8-K, filed on
August 3, 2016.
4.99
4.100
Registration Rights Agreement, dated August 2, 2016, among NRG
Energy, Inc., the guarantors named therein and Morgan Stanley & Co.
LLC, as representative to the initial purchasers listed in Schedule I
thereto.
Incorporated herein by reference to Exhibit 4.4 to the
Registrant's Current Report on Form 8-K, filed on
August 3, 2016.
Supplemental Indenture, dated December 7, 2017, among NRG
Energy, Inc., the guarantors named therein and Delaware Trust
Company, as trustee.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant's Current Report on Form 8-K, filed on
December 8, 2017.
4.101
Form of 5.75% Senior Notes due 2028
Registration Rights Agreement, dated December 7, 2017, among NRG
Energy, Inc., the guarantors named therein and Citigroup Global
Markets, Inc., as representative to the initial purchasers listed in
Schedule I thereto.
Note Agreement, dated August 20, 1993, between NRG Energy, Inc.,
Energy Center, Inc. and each of the purchasers named therein.
Master Shelf and Revolving Credit Agreement, dated August 20, 1993,
between NRG Energy, Inc., Energy Center, Inc., The Prudential
Insurance Registrants of America and each Prudential Affiliate, which
becomes party thereto.
Form of NRG Energy Inc. Long-Term Incentive Plan Deferred Stock
Unit Agreement for Officers and Key Management.
Form of NRG Energy, Inc. Long-Term Incentive Plan Deferred Stock
Unit Agreement for Directors.
Form of NRG Energy, Inc. Long-Term Incentive Plan Non-Qualified
Stock Option Agreement.
Incorporated herein by reference to Exhibit 4.3 to the
Registrant's Current Report on Form 8-K, filed on
December 8, 2017.
Incorporated herein by reference to Exhibit 4.4 to the
Registrant's Current Report on Form 8-K, filed on
December 8, 2017.
Incorporated herein by reference to Exhibit 10.5 to the
Registrant's Registration Statement on Form S-1, as
amended, Registration No. 333-33397.
Incorporated herein by reference to Exhibit 10.4 to the
Registrant's Registration Statement on Form S-1, as
amended, Registration No. 333-33397.
Incorporated herein by reference to Exhibit 10.14 to the
Registrant's annual report on Form 10-K filed on March
30, 2005.
Incorporated herein by reference to Exhibit 10.15 to the
Registrant's annual report on Form 10-K filed on March
30, 2005.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's quarterly report on Form 10-Q filed on
November 9, 2004.
Form of NRG Energy, Inc. Long-Term Incentive Plan Restricted Stock
Unit Agreement for Officers.
Filed herewith.
Form of NRG Energy, Inc. Long-Term Incentive Plan Restricted Stock
Unit Agreement for Non-Officers.
Filed herewith
Form of NRG Energy, Inc. Long-Term Incentive Plan Performance
Stock Unit Agreement.
Second Amended and Restated Annual Incentive Plan for Designated
Corporate Officers.
Incorporated herein by reference to Exhibit 10.7 to the
Registrant's annual report on Form 10-K filed on
February 23, 2010.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's current report on Form 8-K filed on May 7,
2015.
Railroad Car Full Service Master Leasing Agreement, dated as of
February 18, 2005, between General Electric Railcar Services
Corporation and NRG Power Marketing Inc.
Incorporated herein by reference to Exhibit 10.28 to the
Registrant's annual report on Form 10-K filed on
March 30, 2005.
Purchase Agreement (West Coast Power) dated as of December 27,
2005, by and among NRG Energy, Inc., NRG West Coast LLC (Buyer),
DPC II Inc. (Seller) and Dynegy, Inc.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's current report on Form 8-K filed on
December 28, 2005.
Purchase Agreement (Rocky Road Power), dated as of December 27,
2005, by and among Termo Santander Holding, L.L.C.(Buyer),
Dynegy, Inc., NRG Rocky Road LLC (Seller) and NRG Energy, Inc.
Incorporated herein by reference to Exhibit 10.2 to the
Registrant's current report on Form 8-K filed on
December 28, 2005.
Stock Purchase Agreement, dated as of August 10, 2005, by and
between NRG Energy, Inc. and Credit Suisse First Boston Capital
LLC.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's current report on Form 8-K filed on August
11, 2005.
Agreement with respect to the Stock Purchase Agreement, dated
December 19, 2008, by and between NRG Energy, Inc. and Credit
Suisse First Boston Capital LLC.
Incorporated herein by reference to Exhibit 10.13 to the
Registrant's annual report on Form 10-K filed on
February 12, 2009.
4.102
10.1
10.2
10.3*
10.4*
10.5*
10.6*
10.7*
10.8*
10.9*
10.10
10.11
10.12
10.13
10.14
234
235
10.15
10.16†
10.17*
10.18*
10.19*
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
10.29
10.30
10.31
10.32
10.33†
Investor Rights Agreement, dated as of February 2, 2006, by and
among NRG Energy, Inc. and Certain Stockholders of NRG Energy,
Inc. set forth therein.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's current report on Form 8-K filed on
February 8, 2006.
Terms and Conditions of Sale, dated as of October 5, 2005, between
Texas Genco II LP and Freight Car America, Inc., (including the
Proposal Letter and Amendment thereto).
Incorporated herein by reference to Exhibit 10.32 to the
Registrant's annual report on Form 10-K filed on March
7, 2006.
Amended and Restated Employment Agreement, dated December 4,
2008, between NRG Energy, Inc. and David Crane.
Incorporated herein by reference to Exhibit 10.16 to the
Registrant's annual report on Form 10-K filed on
February 12, 2009.
Amendment 2014-1 to the Amended and Restated Employment
Agreement between NRG Energy, Inc. and David Crane, dated
December 4, 2014.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's current report on Form 8-K filed on
December 10, 2014.
General Release, dated January 4, 2016, between NRG Energy, Inc.
and David Crane.
Limited Liability Company Agreement of NRG Common Stock
Finance I LLC.
Incorporated herein by reference to Exhibit 10.2 to the
Registrant's current report on Form 8-K/A filed on
January 8, 2016.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's current report on Form 8-K filed on August
10, 2006.
Note Purchase Agreement, dated August 4, 2006, between NRG
Common Stock Finance I LLC, Credit Suisse International and Credit
Suisse Securities (USA) LLC.
Incorporated herein by reference to Exhibit 10.3 to the
Registrant's current report on Form 8-K filed on August
10, 2006.
Amendment Agreement, dated February 27, 2008, to the Note
Purchase Agreement by and among NRG Common Stock Finance I
LLC, Credit Suisse International, and Credit Suisse Securities (USA)
LLC.
Amendment Agreement, dated December 19, 2008, to the Note
Purchase Agreement by and among NRG Common Stock Finance I
LLC, Credit Suisse International, and Credit Suisse Securities (USA)
LLC.
Amendment Agreement, dated December 19, 2008, to the Note
Purchase Agreement by and among NRG Common Stock Finance II
LLC, Credit Suisse International, and Credit Suisse Securities (USA)
LLC.
Agreement with respect to Note Purchase Agreement, dated
December 19, 2008, by and among NRG Common Stock Finance I
LLC, NRG Energy, Inc., Credit Suisse International, and Credit Suisse
Securities (USA) LLC.
Agreement with respect to Note Purchase Agreement, dated
December 19, 2008, by and among NRG Common Stock Finance II
LLC, NRG Energy, Inc., Credit Suisse International, and Credit Suisse
Securities (USA) LLC.
Incorporated herein by reference to Exhibit 10.5 to the
Registrant's quarterly report on Form 10-Q filed on May
1, 2008.
Incorporated herein by reference to Exhibit 10.23 to the
Registrant's annual report on Form 10-K filed on
February 12, 2009.
Incorporated herein by reference to Exhibit 10.26 to the
Registrant's annual report on Form 10-K filed on
February 12, 2009.
Incorporated herein by reference to Exhibit 10.24 to the
Registrant's annual report on Form 10-K filed on
February 12, 2009.
Incorporated herein by reference to Exhibit 10.27 to the
Registrant's annual report on Form 10-K filed on
February 12, 2009.
Preferred Interest Purchase Agreement, dated August 4, 2006,
between NRG Common Stock Finance I LLC, Credit Suisse Capital
LLC and Credit Suisse Securities (USA) LLC, as agent.
Incorporated herein by reference to Exhibit 10.5 to the
Registrant's current report on Form 8-K filed on August
10, 2006.
Preferred Interest Amendment Agreement, dated February 27, 2008,
by and among NRG Common Stock Finance I LLC, Credit Suisse
Capital LLC, and Credit Suisse Securities (USA) LLC.
Incorporated herein by reference to Exhibit 10.6 to the
Registrant's quarterly report on Form 10-Q filed on May
1, 2008.
Preferred Interest Amendment Agreement, dated December 19, 2008,
by and among NRG Common Stock Finance I LLC, Credit Suisse
International, and Credit Suisse Securities (USA) LLC.
Incorporated herein by reference to Exhibit 10.31 to the
Registrant's annual report on Form 10-K filed on
February 12, 2009.
Preferred Interest Amendment Agreement, dated December 19, 2008,
by and among NRG Common Stock Finance II LLC, Credit Suisse
Capital LLC, and Credit Suisse Securities (USA) LLC.
Incorporated herein by reference to Exhibit 10.34 to the
Registrant's annual report on Form 10-K filed on
February 12, 2009.
Agreement with respect to Preferred Interest Purchase Agreement,
dated December 19, 2008, by and among NRG Common Stock
Finance I LLC, NRG Energy, Inc., Credit Suisse Capital LLC, and
Credit Suisse Securities (USA) LLC.
Agreement with respect to Preferred Interest Purchase Agreement,
dated December 19, 2008, by and among NRG Common Stock
Finance II LLC, NRG Energy, Inc., Credit Suisse Capital LLC, and
Credit Suisse Securities (USA) LLC.
Amended and Restated Contribution Agreement (NRG), dated
March 25, 2008, by and among Texas Genco Holdings, Inc., NRG
South Texas LP and NRG Nuclear Development Company LLC and
Certain Subsidiaries Thereof.
Incorporated herein by reference to Exhibit 10.32 to the
Registrant's annual report on Form 10-K filed on
February 12, 2009.
Incorporated herein by reference to Exhibit 10.35 to the
Registrant's annual report on Form 10-K filed on
February 12, 2009.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's quarterly report on Form 10-Q filed on May
1, 2008.
10.34†
10.35†
10.36†
10.37†
10.38
10.39†
10.40*
10.41†
10.42†
10.43(a)
10.43(b)
10.44*
10.45
Contribution Agreement (Toshiba), dated February 29, 2008, by and
between Toshiba Corporation and NRG Nuclear Development
Company LLC.
Incorporated herein by reference to Exhibit 10.2 to the
Registrant's quarterly report on Form 10-Q filed on May
1, 2008.
Multi-Unit Agreement, dated February 29, 2008, by and among
Toshiba Corporation, NRG Nuclear Development Company LLC and
NRG Energy, Inc.
Incorporated herein by reference to Exhibit 10.3 to the
Registrant's quarterly report on Form 10-Q filed on May
1, 2008.
Amended and Restated Operating Agreement of Nuclear Innovation
North America LLC, dated May 1, 2008.
LLC Membership Interest Purchase Agreement between Reliant
Energy, Inc. and NRG Retail LLC, dated as of February 28, 2009.
Project Agreement, Settlement Agreement and Mutual Release, dated
March 1, 2010, by and among by and among Nuclear Innovation North
America LLC, the City of San Antonio acting by and through the City
Public Service Board of San Antonio, a Texas municipal utility, NINA
Texas 3 LLC and NINA Texas 4 LLC, and solely for purposes of certain
sections of the Settlement Agreement, by NRG Energy, Inc and NRG
South Texas LP.
Incorporated herein by reference to Exhibit 10.4 to the
Registrant's quarterly report on Form 10-Q filed on May
1, 2008.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's quarterly report on Form 10-Q filed on
April 30, 2009.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's current report on Form 8-K filed on
March 2, 2010.
STP 3 & 4 Owners Agreement, dated March 1, 2010, by and among
Nuclear Innovation North America LLC, the City of San Antonio,
NINA Texas 3 LLC and NINA Texas 4 LLC.
Incorporated herein by reference to Exhibit 10.2 to the
Registrant's current report on Form 8-K filed on
March 2, 2010.
Amended and Restated Executive Change-in-Control and General
Severance Plan.
Filed herewith.
Investment and Option Agreement by and among NINA Investments
Holdings LLC, Nuclear Innovation North America LLC and TEPCO
Nuclear Energy America LLC, dated as of May 10, 2010.
Incorporated herein by reference to Exhibit 10.3 to the
Registrant's quarterly report on Form 10-Q filed on
August 2, 2010.
Parent Company Agreement by and among NRG Energy, Inc., Nuclear
Innovation North America LLC, The Tokyo Electric Power Company
and TEPCO Nuclear Energy America LLC, dated as of May 10, 2010.
Incorporated herein by reference to Exhibit 10.4 to the
Registrant's quarterly report on Form 10-Q filed on
August 2, 2010.
Letter of Credit and Reimbursement Agreement, dated as of June 30,
2010, by and among NRG LC Facility Company LLC, NRG Energy,
Inc. and Citibank, N.A.
Incorporated herein by reference to Exhibit 10.2(a) the
Registrant's current report on Form 8-K filed on July 1,
2010.
Letter of Credit and Reimbursement Agreement, dated as of June 30,
2010, by and among NRG LC Facility Company LLC, NRG Energy,
Inc. and Deutsche Bank AG, New York Bank.
Incorporated herein by reference to Exhibit 10.2(b) to
the Registrant's current report on Form 8-K filed on July
1, 2010.
The NRG Energy, Inc. Amended and Restated Long-Term Incentive
Plan.
Amended and Restated Credit Agreement, dated July 1, 2011, by and
among NRG Energy, Inc., the lenders party thereto, the joint lead
bookrunners and joint lead arrangers party thereto, Citicorp North
America, Inc., Morgan Stanley Senior Funding, Inc. and the
documentation agents party thereto.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's current report on Form 8-K filed on April
28, 2017.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's current report on Form 8-K filed on July 5,
2011.
10.46*
Form of Market Stock Unit Grant Agreement.
10.47
Registration Rights Agreement, dated September 24, 2012, among
NRG Energy, Inc., the guarantors named therein and Deutsche Bank
Securities Inc., Merrill, Lynch, Pierce, Fenner & Smith Incorporated,
Barclays Capital Inc., Citigroup Global Markets Inc., Credit Suisse
Securities (USA) LLC, Goldman, Sachs & Co., J.P. Morgan Securities
LLC, Morgan Stanley & Co. LLC and RBS Securities Inc., as initial
purchasers.
10.48*
NRG 2010 Stock Plan for GenOn Employees.
10.49
10.50
Revolving Credit Agreement among GenOn Energy, Inc., as Borrower,
GenOn Americas, Inc., as Borrower, the several lenders from time to
time parties thereto, and NRG Energy, Inc., as Administrative Agent,
dated as of December 14, 2012.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's current report on Form 8-K/A filed on
September 12, 2011.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's current report on Form 8-K filed on
September 24, 2012.
Incorporated herein by reference to Exhibit 10.49 to the
Registrant’s annual report on Form 10-K filed on
February 27, 2013.
Incorporated herein by reference to Exhibit 10.50 to the
Registrant’s annual report on Form 10-K filed on
February 27, 2013.
First Amendment Agreement, dated as of February 6, 2013, to the
Amended and Restated Credit Agreement and the Second Amended
and Restated Collateral Trust Agreement.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant’s quarterly report on Form 10-Q filed on May
7, 2013.
236
237
10.51
10.52*
10.53*
Second Amendment Agreement, dated as of June 4, 2013, to the
Amended and Restated Credit Agreement, the Second Amended and
Restated Collateral Trust Agreement and the Amended and Restated
Guarantee and Collateral Agreement.
NRG Energy, Inc. Long-Term Incentive Plan Market Stock Unit
Agreement.
NRG Energy, Inc. 2010 Stock Plan For GenOn Employees Market
Stock Unit Agreement
10.54*
Amended and Restated Employee Stock Purchase Plan.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant’s current report on Form 8-K filed on June
10, 2013.
Incorporated herein by reference to Exhibit 10.53 to the
Registrant's annual report on Form 10-K filed on
February 28, 2014.
Incorporated herein by reference to Exhibit 10.54 to the
Registrant's annual report on Form 10-K filed on
February 28, 2014.
Incorporated herein by reference to Exhibit 10.2 to the
Registrant's current report on Form 8-K filed on April
28, 2017.
10.55
10.56
10.57
10.58
10.59
10.60
10.61
10.62
10.63(a)
10.63(b)
10.64(a)
10.64(b)
10.65
10.66
Amendment Agreement, dated as of December 23, 2014, by and
between NRG Energy, Inc. and Credit Suisse First Boston Capital
LLC.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's current report on Form 8-K filed on
December 30, 2014.
Employment Agreement, dated December 21, 2015, by and between
NRG Energy, Inc. and Mauricio Gutierrez.
Amendment and Restatement Agreement, dated as of June 30, 2016,
to the Amended and Restated Credit Agreement, the Second Amended
and Restated Collateral Trust Agreement and the Amended and
Restated Guarantee and Collateral Agreement.
Second Amended and Restated Credit Agreement, dated as of June 30,
2016, by and among NRG Energy, Inc., the lenders party thereto, the
joint lead arrangers and joint lead bookrunners party thereto, Citicorp
North America, Inc., Commerzbank AG, New York Branch, Keybank
Capital Markets Inc. and CIT Bank, N.A.
First Amendment Agreement, dated as of January 24, 2017, dated as
of January 24, 2017, by and among NRG Energy, Inc., the lenders
from time to time parties thereto and Citicorp North America, Inc., as
administrative agent and collateral agent.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's current report on Form 8-K filed on
December 24, 2015.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's quarterly report on Form 10-Q filed on
August 9, 2016.
Incorporated herein by reference to Exhibit 10.2 to the
Registrant's quarterly report on Form 10-Q filed on
August 9, 2016.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's Current Report on Form 8-K filed on
January 24, 2017.
Cooperation Agreement, dated as of February 13, 2017, by and among
NRG Energy, Inc., Elliott Associates, L.P., Elliott International, L.P.
and Elliott International Capital Advisors Inc.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's Current Report on Form 8-K filed on
February 13, 2017.
Cooperation Agreement, dated as of February 13, 2017, by and among
NRG Energy, Inc., Bluescape Energy Partners LLC and BEP Special
Situations 2 LLC.
Incorporated herein by reference to Exhibit 10.2 to the
Registrant's Current Report on Form 8-K filed on
February 13, 2017.
Consent Agreement, dated as of May 22, 2017, by and among GenOn
Energy, Inc., NRG Energy, Inc. and the holders of Notes signatory
thereto.
Restructuring Support and Lock-Up Agreement, dated as of June 12,
2017, by and among GenOn Energy, Inc., GenOn Americas
Generation, LLC, the subsidiaries signatory thereto, NRG Energy, Inc.
and the noteholders signatory thereto.
First Amendment, dated as of October 2, 2017, to the Restructuring
Support and Lock-Up Agreement, dated as of June 12, 2017, by and
among GenOn Energy, Inc., GenOn Americas Generation, LLC, NRG
Energy, Inc. and the consenting noteholders party thereto.
Backstop Commitment Letter, dated as of June 12, 2017, by and among
GenOn Energy, Inc., GenOn Americas Generation, LLC, the
subsidiaries signatory thereto and the noteholders signatory thereto.
Incorporated herein by reference to Exhibit 10.1 to
GenOn Energy, Inc. and GenOn Americas Generation,
LLC's Current Report on Form 8-K filed on May 23,
2017.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's Current Report on Form 8-K filed on June
14, 2017.
Incorporated herein by reference to Exhibit 10.2 to the
Registrant's Current Report on Form 8-K filed on
October 6, 2017.
Incorporated herein by reference to Exhibit 10.2 to the
Registrant's Current Report on Form 8-K filed on June
14, 2017.
Amended and Restated Backstop Commitment Letter, dated as of
October 2, 2017, by and among GenOn Energy, Inc., GenOn Americas
Generation, LLC, the guarantors party thereto and backstop parties
thereto.
Backstop Fee Letter, dated as of June 12, 2017, by and among GenOn
Energy, Inc., GenOn Americas Generation, LLC, the subsidiaries
signatory thereto and the noteholders signatory thereto.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's Current Report on Form 8-K filed on
October 6, 2017.
Incorporated herein by reference to Exhibit 10.3 to the
Registrant's Current Report on Form 8-K filed on June
14, 2017.
Consent Agreement, by and among GenOn, GAG and the Consenting
Holders, dated as of October 30, 2017.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's Current Report on Form 8-K filed on
October 31, 2017.
10.67
10.68
10.69
10.70
10.71
10.72
10.73*
10.74*
10.75†
12.1
12.2
21.1
23.1
31.1
31.2
31.3
32
Settlement Agreement, dated as of December 14, 2017, by and between
NRG Energy, Inc. on behalf of itself and the NRG Parties, GenOn
Energy, Inc. on behalf of itself and the Debtors.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's Current Report on Form 8-K filed on
December 18, 2017.
Transition Services Agreement, dated as of December 14, 2017, by
and between GenOn Energy, Inc. and NRG Energy, Inc.
Cooperation Agreement, dated as of December 14, 2017, by and
between GenOn Energy, Inc. and NRG Energy, Inc.
Pension Indemnity Agreement, dated as of December 14, 2017, by and
between NRG Energy, Inc. and GenOn Energy, Inc.
Employee Matters Agreement, dated as of December 14, 2017, by and
between NRG Energy, Inc. and GenOn Energy, Inc.
Incorporated herein by reference to Exhibit 10.2 to the
Registrant's Current Report on Form 8-K filed on
December 18, 2017.
Incorporated herein by reference to Exhibit 10.3 to the
Registrant's Current Report on Form 8-K filed on
December 18, 2017.
Incorporated herein by reference to Exhibit 10.4 to the
Registrant's Current Report on Form 8-K filed on
December 18, 2017.
Incorporated herein by reference to Exhibit 10.5 to the
Registrant's Current Report on Form 8-K filed on
December 18, 2017.
Tax Matters Agreement, initially dated as of December 14, 2017, by
and between NRG Energy, Inc. and GenOn Energy, Inc. and by
Reorganized GenOn upon the Effective Date.
Incorporated herein by reference to Exhibit 10.5 to the
Registrant's Current Report on Form 8-K filed on
December 18, 2017.
Form of NRG Energy, Inc. Long-Term Incentive Plan Relative
Performance Stock Unit Agreement for Officers.
Filed herewith.
Form of NRG Energy, Inc. Long-Term Incentive Plan Relative
Performance Stock Unit Agreement for Senior Vice Presidents.
Filed herewith.
Consent and Indemnity Agreement, dated as of February 6, 2018, by
and among NRG Energy, Inc., NRG Repowering Holdings LLC, NRG
Yield, Inc., and GIP III Zephyr Acquisition Partners, L.P., and NRG
Yield Operating LLC (solely with respect to Sections E.5, E.6 and G.
12).
Incorporated herein by reference to Exhibit 10.34 to
NRG Yield, Inc.'s Annual Report on Form 10-K filed on
March 1, 2018.
NRG Energy, Inc. Computation of Ratio of Earnings to Fixed Charges.
Filed herewith.
NRG Energy, Inc. Computation of Ratio of Earnings to Fixed Charges
and Preferred Stock Dividend Requirements.
Filed herewith.
Subsidiaries of NRG Energy, Inc.
Consent of KPMG LLP.
Rule 13a-14(a)/15d-14(a) certification of Mauricio Gutierrez.
Rule 13a-14(a)/15d-14(a) certification of Kirkland B. Andrews.
Rule 13a-14(a)/15d-14(a) certification of David Callen.
Filed herewith.
Filed herewith.
Filed herewith.
Filed herewith.
Filed herewith.
Section 1350 Certification.
Furnished herewith.
101 INS
XBRL Instance Document.
101 SCH
XBRL Taxonomy Extension Schema.
101 CAL
XBRL Taxonomy Extension Calculation Linkbase.
101 DEF
XBRL Taxonomy Extension Definition Linkbase.
101 LAB
XBRL Taxonomy Extension Label Linkbase.
101 PRE
XBRL Taxonomy Extension Presentation Linkbase.
Filed herewith.
Filed herewith.
Filed herewith.
Filed herewith.
Filed herewith.
Filed herewith.
*
†
^
Exhibit relates to compensation arrangements.
Portions of this exhibit have been redacted and are subject to a confidential treatment request filed with the Secretary of the Securities
and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended.
This filing excludes schedules pursuant to Item 601(b)(2) of Regulation S-K, which the registrant agrees to furnish supplementary to
the Securities and Exchange Commission upon request by the Commission.
Item 16. Form 10-K Summary
None.
238
239
SIGNATURES
POWER OF ATTORNEY
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned thereunto duly authorized.
NRG ENERGY, INC.
(Registrant)
By:
/s/ MAURICIO GUTIERREZ
Mauricio Gutierrez
Chief Executive Officer
Date: March 1, 2018
Each person whose signature appears below constitutes and appoints David R. Hill and Brian E. Curci, each or any of them,
such person's true and lawful attorney-in-fact and agent with full power of substitution and resubstitution for such person and in
such person's name, place and stead, in any and all capacities, to sign any and all amendments to this report on Form 10-K, and
to file the same with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange
Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each
and every act and thing necessary or desirable to be done in and about the premises, as fully to all intents and purposes as such
person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them or his or their substitute or
substitutes, may lawfully do or cause to be done by virtue hereof.
In accordance with the Exchange Act, this report has been signed by the following persons on behalf of the registrant in the
capacities indicated on March 1, 2018.
Signature
/s/ MAURICIO GUTIERREZ
Mauricio Gutierrez
/s/ KIRKLAND B. ANDREWS
Kirkland B. Andrews
/s/ DAVID CALLEN
David Callen
/s/ LAWRENCE S. COBEN
Lawrence S. Coben
/s/ E. SPENCER ABRAHAM
E. Spencer Abraham
/s/ KIRBYJON H. CALDWELL
Kirbyjon H. Caldwell
/s/ TERRY G. DALLAS
Terry G. Dallas
/s/ WILLIAM E. HANTKE
William E. Hantke
/s/ PAUL W. HOBBY
Paul W. Hobby
/s/ ANNE C. SCHAUMBURG
Anne C. Schaumburg
/s/ EVAN J. SILVERSTEIN
Evan J. Silverstein
/s/ BARRY T. SMITHERMAN
Barry T. Smitherman
/s/ THOMAS H. WEIDEMEYER
Thomas H. Weidemeyer
/s/ C. JOHN WILDER
C. John Wilder
/s/ WALTER R. YOUNG
Walter R. Young
Title
President, Chief Executive Officer and
Director (Principal Executive Officer)
Chief Financial Officer
(Principal Financial Officer)
Chief Accounting Officer
(Principal Accounting Officer)
Date
March 1, 2018
March 1, 2018
March 1, 2018
Chairman of the Board
March 1, 2018
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
March 1, 2018
March 1, 2018
March 1, 2018
March 1, 2018
March 1, 2018
March 1, 2018
March 1, 2018
March 1, 2018
March 1, 2018
March 1, 2018
March 1, 2018
240
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NRG Energy
804 Carnegie Center
Princeton, NJ
08540-6213
t: 609.524.4500
f: 609.524.4501
nrg.com
1201 Fannin Street
Houston, TX
77002-6929
t: 713.537.3000
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