2018
FORM 10-K
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.
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, 2018.
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 every Interactive Data File required to be submitted 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 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
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 $7,964,294,696 based on the closing sale price of $30.70 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, 2019
280,997,550
Documents Incorporated by Reference:
Portions of the Registrant's definitive Proxy Statement relating to its 2019 Annual Meeting of Stockholders
are incorporated by reference into Part III of this Annual Report on Form 10-K
1
TABLE OF CONTENTS
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
8
8
25
40
41
43
43
44
44
46
47
93
97
97
97
100
101
101
103
104
104
104
105
105
208
201
2
Glossary of Terms
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 $1.7 billion term loan facility due 2023, a component of the Senior Credit
Facility
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
Average realized prices
Volume-weighted average power prices, net of average fuel costs and reflecting the impact
of settled hedges
Bankruptcy Code
Bankruptcy Court
Baseload
BETM
BTU
Business Solutions
CAA
CAISO
Carlsbad
CCF
CDD
CDWR
CFTC
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
California Independent System Operator
Carlsbad Energy Center, a 528 MW natural gas-fired project located in Carlsbad, CA
Carbon Capture Facility
Cooling Degree Day
California Department of Water Resources
U.S. Commodity Futures Trading Commission
Chapter 11 Cases
Voluntary cases commenced by the GenOn Entities under the Bankruptcy Code in the
Bankruptcy Court
C&I
CES
Cleco
CO2
CO2e
ComEd
Company
CPP
CPUC
CWA
D.C. Circuit
Distributed Solar
DNREC
Dominion
DSI
DSU
Commercial, industrial and governmental/institutional
Clean Energy Standard
Cleco Corporate Holdings LLC
Carbon Dioxide
Carbon Dioxide Equivalents
Commonwealth Edison
NRG Energy, Inc.
Clean Power Plan
California Public Utilities Commission
Clean Water Act
U.S. Court of Appeals for the District of Columbia Circuit
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.
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
EGU
Emani
Electric Generating Unit
European Mutual Association for Nuclear Insurance
3
EME
EMAAC
Edison Mission Energy
Eastern Mid-Atlantic Area Council
Energy Plus Holdings
Energy Plus Holdings LLC
EPA
EPC
EPSA
ERCOT
ESP
ESPP
ESPS
U.S. Environmental Protection Agency
Engineering, Procurement and Construction
The Electric Power Supply Association
Electric Reliability Council of Texas, the Independent System Operator and the regional
reliability coordinator of the various electricity systems within Texas
Electrostatic Precipitator
NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan
Existing Source Performance Standards
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 Entities
GenOn Mid-Atlantic
GHG
GIP
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
Greenhouse Gas
Global Infrastructure Partners
Green Mountain Energy
Green Mountain Energy Company
GW
GWh
HAP
HDD
Heat Rate
HLBV
HLW
IASB
IFRS
Indexed Rate
IPPNY
ISO
ISO-NE
ITC
kWh
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
High-level radioactive waste
International Accounting Standards Board
International Financial Reporting Standards
An indexed rate means that the price of the electricity sold to the customer is tied to an
underlying variable, or index, such as monthly closing of NYMEX natural gas
Independent Power Producers of New York
Independent System Operator, also referred to as RTOs
ISO New England Inc.
Investment Tax Credit
Kilowatt-hour
4
LaGen
LIBOR
LSE
LTIPs
LTSA
Louisiana Generating LLC
London Inter-Bank Offered Rate
Load Serving Entities
Collectively, the NRG LTIP and the NRG GenOn LTIP
Long-Term Service Agreement
Mass Market
Residential and small commercial customers
MATS
MDth
Merger
Mercury and Air Toxics Standards promulgated by the EPA
Thousand Dekatherms
The merger completed on December 14, 2012 by NRG and GenOn pursuant to the Merger
Agreement
Midwest Generation
Midwest Generation, LLC
MISO
MMBtu
MSU
MW
MWh
NAAQS
NEIL
NEPOOL
NERC
Midcontinent Independent System Operator, Inc.
Million British Thermal Units
Market Stock Unit
Megawatts
Saleable megawatt hour net of internal/parasitic load megawatt-hour
National Ambient Air Quality Standards
Nuclear Electric Insurance Limited
New England Power Pool
North American Electric Reliability Corporation
Net Capacity Factor
Net Exposure
Net Generation
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
NJBPU
NOL
NOx
NPDES
NPNS
NQSO
NRC
NRG
NRG GenOn LTIP
NRG LTIP
NRG Yield, Inc.
Nuclear Decommissioning
Trust Fund
Nuclear Waste Policy Act
NYISO
NYMEX
NYSPSC
OCI/OCL
ORDC
PA PUC
New Jersey Board of Public Utilities
Net Operating Loss
Nitrogen Oxides
National Pollutant Discharge Elimination System
Normal Purchase Normal Sale
Non-Qualified Stock Option
U.S. Nuclear Regulatory Commission
NRG Energy, Inc.
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 Energy, Inc. Amended and Restated Long-Term Incentive Plan
NRG Yield, Inc., which changed it's name to Clearway energy, Inc. following the sale by NRG
or NRG Yield and the Renewables Platform to GIP
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
New York Independent System Operator
New York Mercantile Exchange
New York State Public Service Commission
Other Comprehensive Income/(Loss)
Operating Reserve Demand Curve
Pennsylvania Public Utility Commission
5
Peaking
PER
Petition Date
PG&E
Pipeline
PJM
PM2.5
PPA
PPM
PSU
PTC
PUCT
PURPA
RCRA
Reliant Energy
REMA
Renewables
Renewables Platform
Restructuring Support
Agreement
Retail
Units expected to satisfy demand requirements during the periods of greatest or peak load
on the system
Peak Energy Rent
June 14, 2017
PG&E Corporation (NYSE: PCG) and its primary operating subsidiary, Pacific Gas and
Electric Company
Projects that range from identified lead to shortlisted with an offtake, and represents a
lower level of execution certainty
PJM Interconnection, LLC
Particulate Matter that has a diameter of less than 2.5 micrometers
Power Purchase Agreement
Parts per million
Performance Stock Unit
Production Tax Credit
Public Utility Commission of Texas
Public Utility Regulatory Policies Act of 1978
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
Consist of the following projects retained by NRG: Agua, Ivanpah, Guam, NFL stadiums
The renewable operating and development platform sold to GIP with NRG's interest in NRG
Yield.
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
Revolving Credit Facility
The Company's $2.4 billion revolving credit facility, a component of the Senior Credit Facility,
due 2021
RGGI
RMR
ROFO
ROFO Agreement
RPM
RPS
RPSU
RSU
RTO
SCE
SCR
SDG&E
SEC
Securities Act
Senior Credit Facility
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
Restricted Stock Unit
Regional Transmission Organization
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
6
Senior Notes
Services Agreement
Settlement Agreement
SNF
SO2
South Central Portfolio
SPP
S&P
STP
STPNOC
Tax Act
As of December 31, 2018, NRG's $3.8 billion outstanding unsecured senior notes consisting
of $733 million of 6.25% senior notes due 2024, $1.0 billion of the 7.25% senior notes due
2026, $1.23 billion of the 6.625% senior notes due 2027, and $821 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
Spent Nuclear Fuel
Sulfur Dioxide
NRG's South Central Portfolio, 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
Term Loan Facility
Prior to June 30, 2016, the Company's $2.0 billion term loan facility due 2018.
Texas Genco
Texas Genco LLC
TSA
TSR
TWCC
TWh
UPMC
U.S.
U.S. DOE
Utility-Scale Solar
VaR
VCP
VIE
WECC
ZECs
Transportation Services Agreement
Total Shareholder Return
Texas Westmoreland Coal Co.
Terawatt Hour
University of Pittsburgh Medical Center
United States of America
U.S. Department of Energy
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
Value at Risk
Voluntary Clean-Up Program
Variable Interest Entity
Western Electricity Coordinating Council
Zero Emissions Credits
7
Item 1 — Business
General
PART I
NRG Energy, Inc., or NRG or the Company, is an energy company built on dynamic retail brands with diverse generation
assets. NRG brings the power of energy to consumers 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. NRG is
perfecting the integrated model by balancing retail load with generation supply within its deregulated markets, while evolving
to a customer-driven business. The Company sells energy, services, and innovative, sustainable products and services directly
to retail customers under the names "NRG" and "Reliant" and other brand names owned by NRG supported by approximately
23,000(a) MW of generation as of December 31, 2018. 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 innovative solutions to the end-use energy
consumer. This strategy is designed to enable the Company to optimize the integrated model to generate predictable cash flow,
significantly strengthen earnings and cost competitiveness, and lower risk and volatility. Sustainability is an integral piece of
NRG's strategy and ties directly to business success, reduced risks and brand value.
To effectuate the Company’s strategy, NRG is focused on: (i) 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; (ii) deploying
innovative and renewable energy solutions for consumers within its retail businesses; (iii) excellence in operating performance
of its existing assets including optimal hedging of generation assets and retail load operations; and (iv) engaging in a proactive
capital allocation plan within the dictates of prudent balance sheet management.
Transformation Plan
NRG is well underway in executing its Transformation Plan. The Company expects to fully implement the Transformation
Plan by the end of 2020 with a significant portion completed in 2018. The three-part, three-year plan is comprised of the following
targets and the Company's achievements towards such targets are as follows:
Operations and Cost Excellence
Recurring cost savings and margin enhancement of $1,065 million, which consists of $590 million of cumulative 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. The Company
realized annual cost savings of $532 million and $32 million of margin enhancements during the year ended December 31, 2018
and is on track to realize $590 million of cost savings and $135 million of margin enhancements in 2019.
The Company expects to realize (i) $370 million of non-recurring working capital improvements through 2020 and (ii)
approximately $290 million of one-time costs to achieve. By December 31, 2018, NRG has realized $333 million of non-
recurring working capital improvements and $194 million of one-time costs to achieve, and expects to incur approximately $95
million of one-time costs to achieve in 2019.
Portfolio Optimization
Targeted and completed $3.0 billion of asset sale cash proceeds received through February 28, 2019.
Capital Structure and Allocation
As of December 31, 2018, the Company achieved the previously announced target of reducing consolidated corporate debt
to 3.0x net debt / adjusted EBITDA(b) credit ratio on a pro forma basis that includes the South Central Portfolio sale proceeds.
As of February 28, 2019, the Company completed $1.5 billion of share repurchases.
(a) excluding discontinued operations and held for sale
(b) adjusted EBITDA as defined per the Senior Credit Facility
8
Business Overview
As of December 31, 2018, the Company’s core businesses include (i) retail electricity and natural gas for residential,
industrial and commercial consumers, including personal power solutions and Business Solutions, which includes C&I customers
and other distributed and reliability products, and (ii) wholesale conventional generation primarily to support the retail business.
The Company is committed to continuing to evaluate and streamline its generation portfolio to focus on locational value and
supporting the retail business in each of the markets where the Company participates. In furtherance of this goal, during 2018,
NRG divested non-core businesses which included, among others: (i) NRG Yield, Inc. and the Company's Renewables Platform,
and (ii) the Company's South Central Portfolio.
The Company previously had an ownership interest in GenOn Energy, Inc. which filed for bankruptcy on June 14, 2017.
As a result of the bankruptcy filing, NRG determined it no longer controlled GenOn and deconsolidated GenOn and its subsidiaries
for financial reporting purposes. On December 14, 2018, GenOn emerged from bankruptcy as a standalone company no longer
owned by NRG.
Retail
Retail provides energy and related services to residential, industrial and commercial consumers through various brands
and sales channels across the U.S. In 2018, Retail delivered approximately 67 TWhs of electricity and 11 MDth of natural gas
and served approximately 3.1 million customers. Retail's results make it one of the largest competitive energy retailers in the
U.S. As of the end of 2018, Retail has recurring electricity and/or natural gas sales in 19 U.S. states, the District of Columbia,
and 2 provinces in Canada. 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 2018, Business Solutions delivered
approximately 21 TWhs of electricity and managed approximately 2,000 MWs of demand response positions across its portfolio.
Generation
The Company’s wholesale power generation business includes plant operations, commercial operations, EPC, asset
management, energy services and other critical related functions.
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 reliability services. The Company owns a
diversified power generation portfolio with approximately 23,000(a) MW of fossil fuel, nuclear and renewable generation capacity
at 37 plants as of December 31, 2018. In addition, the Company operates approximately 8,200 MW of coal and natural gas
generation at 17 plants on behalf of third parties as of December 31, 2018. 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. Many of
NRG's generation facilities are located near population centers, which often translates into higher revenue. Additionally, NRG's
peaking facilities provide opportunities to capture significant upside potential during periods of high demand, which typically
drive higher energy prices.
(a) excluding discontinued operations and held for sale
9
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 believes that its extensive generation
portfolio provides asset optimization opportunities. NRG continuously evaluates opportunities for development of new
generation, on both a merchant and contracted basis.
10
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, 2018, excluding discontinued operations:
11
The following table summarizes NRG's global generation portfolio as of December 31, 2018:
Generation Type
Natural gas
Coal
Oil
Nuclear
Wind
Utility Scale Solar
Battery Storage & Distributed Solar
Total generation capacity
Global Generation Portfolio(a)(b)(c)
(In MW)
Generation
Texas(f)
4,739
4,174
—
1,126
—
—
2
East/West(d)(e)
5,248
3,745
3,621
—
75
322
—
10,041
13,011
Other
Total Global
—
—
—
—
—
—
60
60
9,987
7,919
3,621
1,126
75
322
62
23,112
(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) The NRG Yield Inc. and the Renewables Platform businesses, which represented 3,428 MW of global generation, were sold on August 31, 2018
(c) Excludes the South Central Portfolio, except for Cottonwood, which was sold on February 4, 2019, as well as the 528 MW natural gas-fired project in
Carlsbad, California that was sold on February 27, 2019
(d) Includes the 1,263 MW Cottonwood facility that was sold to Cleco on February 4, 2019, which the Company is leasing until 2025
(e) Includes International and Renewables
(f) Does not include plants outside of the ERCOT market or the Sherbino wind farm, which are included in East/West
The Company 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. This offsetting nature, 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.
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 2022. In addition,
NRG's cleared capacity revenues not only enhance the reliability of future cash flows but are not correlated to natural gas prices
during the contracted period. As of December 31, 2018, the Company had purchased fuel forward under fixed price contracts,
with contractually-specified price escalators, for approximately 68% of its expected coal requirement from 2019 to 2020. The
Company enters into additional hedges when it believes market conditions are favorable.
Commercial Operations Overview
NRG seeks to maximize profitability and manage cash flow volatility through the marketing, trading and sale of energy,
capacity and ancillary services into spot, intermediate and long-term markets and through the active management and trading
of transmission rights, emissions allowances, renewable energy credits, fuel supplies and transportation-related services. The
Company's principal objectives are the realization of the full market value of its overall portfolio, 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 supply contracts, 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 purchases and sales contracts to manage
the commodity price risk. The objective of these hedging strategies is to stabilize the cash flow generated by NRG's overall
portfolio.
12
In addition to power purchases and 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.
Retail Operations
NRG's retail businesses sell 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 2018, NRG's retail businesses sold approximately
67 TWhs of electricity and 11 MDth of natural gas. In any given year, the quantity of TWhs and MDth sold can be affected by
weather, economic conditions and competition. The wholesale supply is typically purchased as the anticipated 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.
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 and other long-term contractual
arrangements:
Capacity auctions — The Company's largest sources of capacity revenues are capacity auctions in PJM and ISO-NE. Both
PJM and ISO-NE 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.
2021/2022 PJM Auction Results — On May 23, 2018, PJM announced the results of its 2021/2022 base residual
auction. NRG cleared approximately 4,619 MW of Capacity Performance product for the generation fleet.
NRG's expected capacity revenues from the base residual auction for the 2021/2022 delivery year are
approximately $322 million. The table below provides a detailed description of NRG’s 2021/2022 base residual
auction results from May 23, 2018:
Zone
COMED
EMAAC
PEPCO
Total
Generation
Cleared Capacity (MW)
3,995
552
72
4,619
Price ($/MW-day)
195.55
165.73
140.00
$
$
$
NRG through its demand response business received a capacity award of 3,194 MWs at a volume weighted
average price of $155.16 per MW-day, or $181 million of revenue, and pays out a portion of these revenues
to our customers reflected as cost of sales.
2022/2023 ISO-NE Auction Results - On February 6, 2019 ISO-NE announced the results of its 2022/2023
forward capacity auction. NRG cleared 1,517 MW of capacity. NRG's expected capacity revenues from the
auction for the 2022/2023 delivery year are approximately $69 million.
13
Resource adequacy and bilateral contracts — In California, there is a resource adequacy requirement which 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.
Bilateral contracts — The Company enters into physical power bilateral contracts for the sale of energy from our generation
fleet as part of the Company's portfolio optimization strategy. Counterparties to the contracts are either third parties or our Retail
segment. The Company primarily sells physical capacity forward through bilateral contracts for our New York assets. To the
extent NRG is not able to enter into a physical bilateral contract, NRG will sell the remaining capacity into the NYISO six month
strip, monthly or spot auctions.
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 2019. NRG actively manages its coal requirements based on forecasted generation, market volatility and its
inventory on site. As of December 31, 2018, NRG had purchased forward contracts to provide fuel for approximately 68% of
the Company's expected requirements from 2019 through 2020. NRG purchased approximately 23 million tons of coal in 2018,
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 2 years.
The following table shows the percentage of the Company's coal requirements from 2019 through 2020 that have been
purchased forward as of December 31, 2018:
2019
2020
Percentage of
Company's
Requirement
100%
36%
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.
14
Operational Statistics
Retail
The following are industry statistics for the Company's customer count, load and economic gross margin per MWh:
Sales volumes (in GWh)
Mass electricity - Texas
Mass electricity - All other regions
C&I electricity - Texas
C&I electricity - All other regions
Total Load
Customer count - Electricity (in thousands)
Texas
Average Retail Mass
Ending Retail Mass
All other regions
Average Retail Mass
Ending Retail Mass
Customer count - Natural gas (in thousands)
Average Retail Mass
Ending Retail Mass
Gross margin and economic gross margin
Gross margin (in millions)
Economic gross margin (in millions)
Gross margin per MWh
Economic gross margin per MWh
Customer contract mix
Term
Variable
Indexed
Years ended December 31,
2018
2017
2016
37,846
7,968
20,192
984
66,990
36,169
6,221
19,586
814
62,790
2,176
2,291
790
903
2,139
2,159
675
673
35,102
6,764
17,540
1,366
60,772
2,058
2,102
679
671
64
99
11
15
8
9
$ 2,055
1,802
30.68
26.91
$ 1,778
1,602
28.32
25.51
$ 2,006
1,649
33.01
27.13
65%
25%
10%
100%
70%
22%
8%
100%
70%
23%
7%
100%
15
Generation
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, 2018 and 2017:
Year Ended December 31, 2018
Fossil and Nuclear Plants (a)
Net Generation
Generation
Texas
East/West/Other (b)
Other (c)
Generation
Texas
East/West/Other (b)
Other (c)
Net Owned
Capacity (MW)
10,161
13,037
60
Net Owned
Capacity (MW)
10,159
14,594
114
(MWh)
(In thousands) (a)
Annual Equivalent
Availability Factor
Average Net Heat
Rate BTU/kWh
Net Capacity
Factor
38,214
21,089
85.2%
82.8%
10,423
9,711
44.7%
17.8%
Year Ended December 31, 2017
Fossil and Nuclear Plants (a)
Net Generation
(MWh)
(In thousands) (a)
Annual Equivalent
Availability Factor
Average Net Heat
Rate BTU/kWh
Net Capacity
Factor
38,694
21,338
90.4%
84.7%
10,490
9,738
45.0%
16.4%
(a) Net generation excludes equity method investments
(b)
(c) The net capacity figure within "Other" includes the aggregate production capacity of installed and activated residential solar energy systems
Includes International, NRG renewable assets, Sherbino and the 1,263 MW Cottonwood facility, which NRG will lease back
The generation performance by region for the three years ended December 31, 2018, 2017 and 2016, is shown below:
Generation
Texas
Coal
Gas
Nuclear (a)
Total Texas
East/West
Coal
Oil
Gas
Renewables
Total East/West
(a) MWh information reflects the Company's undivided interest in total MWh generated by STP
16
2018
Net Generation
2017
(In thousands of MWh)
2016
24,781
4,415
9,018
38,214
7,965
544
11,797
783
21,089
24,757
4,428
9,509
38,694
8,403
319
10,949
1,667
21,338
21,738
6,379
9,559
37,676
9,931
318
11,671
1,828
23,748
Greenhouse Gas Emissions — NRG emits CO2 and small quantities of other GHGs (0.6% of total) when generating
electricity at a majority of its facilities. The graphs presented below illustrate NRG's domestic emissions of CO2e for the 2014
through 2018 period. A significant majority (>99%) of NRG's emission sources are subject to federal (U.S. EPA) GHG reporting
requirements programs. From 2014 to 2018, the Company's CO2e emissions decreased from 72 million metric tons to 46 million
metric tons, representing a 36% reduction. The primary factor leading to the decreased emissions include reductions in fleet net
generation due to a market-driven shift from coal as a primary fuel to natural gas. The Company's goal is to reduce CO2e emissions
by 50% by 2030, and 90% by 2050, using 2014 as a baseline.
As of December 31, 2018, less than 25% of the Company's consolidated operating revenues were derived from coal-fired
operating assets.
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.
17
Segment Review
The Company's segment structure reflects how management currently makes financial decisions and allocates resources.
The Company's businesses are segregated as follows: Retail, which includes Mass customers and Business Solutions, which
includes C&I customers and other distributed and reliability products; and Generation, which includes all power plant activities,
domestic and international, as well as renewables. 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.
As further described in Note 3, Acquisitions, Discontinued Operations and Dispositions, the Company is treating the
following businesses as discontinued operations, which have been recast to present in the corporate segment:
• South Central Portfolio
• NRG Yield, Inc. and its Renewables Platform
• Carlsbad
• GenOn
Revenues
The following table contains a summary of NRG's operating revenues by segment for the years ended December 31, 2018,
2017 and 2016, as discussed in Item 15 — Note 17, 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.
Year Ended December 31, 2018
Energy
Revenues
Capacity
Revenues
Retail
Revenues
Mark-to-
Market
Activities
Contract
Amortization
Other
Revenues(a)
Total
Operating
Revenues(b)
(In millions)
Generation
Retail
Corporate and Eliminations (b)
Total
$
2,677
$
670
$
— $
(202) $
— $
287
$
—
(1,129)
—
—
7,110
(5)
(7)
79
—
—
—
(2)
3,432
7,103
(1,057)
$
1,548
$
670
$
7,105
$
(130) $
— $
285
$
9,478
(a) Consists 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, 2017
Energy
Revenues
Capacity
Revenues
Retail
Revenues
Mark-to-
Market
Activities
Contract
Amortization
Other
Revenues(c)
Total
Operating
Revenues(d)
(In millions)
Generation
Retail
Corporate and Eliminations (d)
Total
(c) Consists of operation and maintenance revenues and energy service revenues, primarily at BETM (Generation segment)
(d) Energy revenues include inter-segment sales primarily between Generation and Retail
(1,089)
— $
6,374
1,636
6,378
2,725
219
612
252
618
(4)
(6)
37
—
—
—
$
$
$
4
$
$
$
$
$
$
(1)
— $
(1) $
235
$
—
(38)
197
$
3,615
6,369
(910)
9,074
Year Ended December 31, 2016
Energy
Revenues
Capacity
Revenues
Retail
Revenues
Mark-to-
Market
Activities
Contract
Amortization
Other
Revenues(e)
Total
Operating
Revenues(f)
(In millions)
Generation
Retail
Corporate and Eliminations(f)
Total
(e) Consists of operation and maintenance revenues and energy service revenues, primarily at BETM (Generation segment)
(f) Energy revenues include inter-segment sales primarily between Generation and Retail
(636) $
(565) $
— $
6,332
2,269
6,368
3,243
(974)
(70)
637
642
(1)
(5)
36
—
—
—
$
$
$
$
$
$
$
(1)
— $
(1) $
313
$
—
(35)
278
$
3,633
6,330
(1,048)
8,915
18
Seasonality and Price Volatility
Annual and quarterly operating results of the Company's wholesale power generation segments can be significantly affected
by weather and energy commodity price volatility. Significant other events, such as the demand for natural gas, interruptions in
fuel supply infrastructure and relative levels of hydroelectric capacity can increase seasonal fuel and power price volatility. 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
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 consumer choice, NRG's retail businesses competitively offer retail
power, natural gas, portable power and 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 in each state across the country.
Wholesale
NRG's fleet operates in 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.
Texas
NRG's Texas wholesale power generation business is located in the ERCOT market. 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 referred to as the Operating Reserve Demand Curve (ORDC) to provide pricing more reflective of higher energy
value when operating reserves are scarce or constrained. The PUCT directed the implementation of the ORDC in 2014 to act
as the primary scarcity pricing mechanism and has modified it several times since then, including as recently as January 2019.
19
East/West
NRG's generation and demand response assets located in the East region of the U.S. are within the control areas of ISO-
NE, MISO, 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, MISO, NYISO and PJM. PJM and ISO-NE use a three-year forward capacity auction, while
NYISO uses a month-ahead capacity auction. MISO has an annual auction, known as the Planning Resource 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.
The Company’s Agua Caliente and Ivanpah projects are party to PPAs with PG&E. Both projects have project financing
with the U.S. DOE, and Agua Caliente Borrower 1 LLC, along with Agua Caliente Borrower 2 LLC, which is owned by
Clearway Energy Inc., are party to a back leverage financing related to the Agua Caliente project. On January 29, 2019,
PG&E Corp. and subsidiary utility PG&E filed for Chapter 11 bankruptcy protection. For further discussion see Item 1 -
Energy Regulatory Matters, Note 11 - Debt and Capital Leases and Note 15 - Investments Accounted for by the Equity
Method and Variable Interest Entities.
Energy Regulatory Matters
As owners of power plants and participants in retail and wholesale 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 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
Complaints Ahead of PG&E Corporation Bankruptcy Filing — On January 18, 2019, NextEra filed a petition for declaratory
order requesting that FERC assert its jurisdiction over PG&E's wholesale contracts prior to PG&E's formal bankruptcy filing.
Exelon Corporation and EDF Renewables filed similar complaints. On January 25, 2019, FERC found that it and the bankruptcy
courts have concurrent jurisdiction to review and address the disposition of wholesale power contracts. The matter is in litigation.
State Energy Regulation
State Out-Of-Market Subsidy Proposals — NRG has opposed efforts to provide out-of-market subsidies and intends to
continue opposing them in the future. NRG has petitioned the Supreme Court of the United States to hear cases from the Seventh
and Second Circuit Courts regarding ZECs in Illinois and New York, respectively. NRG is also currently participating in the
NJBPU's proceeding regarding ZECs, and is involved in the informational meetings that the PA PUC is holding regarding the
nuclear subsidy issue.
20
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 22, Regulatory Matters, to the Consolidated Financial Statements.
PJM
Capacity Market Reforms Filing — FERC is considering various proposals to reform the PJM capacity market, including
whether to accommodate state subsidies in the wholesale market or to mitigate subsidized resources, along with other changes.
As part of this process, FERC established a procedural timetable and delayed the 2019 Base Residual Auction until August 2019.
Decisions around harmonizing federal and state policy initiatives is a critical factor for setting future prices.
New England
ISO-NE Retention of Mystic Units — ISO-NE is currently engaged in extensive litigation at FERC regarding how to ensure
system reliability in a gas-constrained system. In particular, FERC has approved ISO-NE's proposal to retain units at the Mystic
generating station, which utilizes liquefied natural gas for fuel security. Among other things, FERC specifically will allow
resources retained for fuel security to enter a zero bid in the Forward Capacity Auction. On January 2, 2019, multiple parties
filed for rehearing. The motions for rehearing are pending at FERC. The outcome of this matter will potentially affect future
capacity market prices.
New York
Independent Power Producers of New York Complaint — A variety of generators have requested that FERC address the
market impacts of out-of-market payments to existing generation in the NYISO. This request was prompted by the ZEC program
initiated by the NYSPSC in 2013, with various requests for FERC to act since. 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. Among other things, the Reset Order placed a price cap on energy supply offers and
imposed burdensome new regulations on customers. Various parties have challenged the NYPSC's authority to regulate prices
charged by competitive suppliers, and that litigation is ongoing.
Texas
ORDC Reforms — In January 2019, the PUCT directed ERCOT to implement changes to its scarcity pricing structure,
known as the ORDC, which is designed to increase the likelihood of scarcity pricing to support existing generation and new
investment. The PUCT directed ORDC reforms to be implemented in two phases of gradually increasing magnitude. The first
phase will become effective prior to the summer of 2019 and the second phase will become effective prior to the summer of
2020.
Environmental Regulatory 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 revisions and legal challenges are
resolved.
21
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.
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. In December 2018, the EPA proposed a finding that regulating HAPs was not "appropriate
and necessary" because the costs far exceed the benefits. Nonetheless, the EPA proposed keeping the substantive requirements
of the MATS rule. 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 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. In August 2018, the EPA published the proposed Affordable Clean Energy, or
ACE, rule to replace the CPP. The ACE rule proposes that the EPA would provide guidelines for states to in turn require heat
rate improvements at coal-fired EGUs to reduce GHG emissions.
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. In September 2017, the EPA agreed to reconsider the rule. On July 30, 2018, the EPA promulgated a rule that
amends the existing ash rule by extending some of the deadlines and providing more flexibility for compliance. On August 21,
2018, the D.C. Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy ponds.
Accordingly, we anticipate that the EPA will promulgate new regulations to address these issues (including compliance deadlines)
as it reconsiders other aspects of the existing rule. The EPA has stated that it intends to further revise the rule. The Company
will provide estimates of the cost of compliance after the rule is revised.
Domestic Site Remediation Matters
Under certain federal, state and local environmental laws, a current or previous owner or operator of a 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 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 23, Environmental Matters, to the Consolidated Financial Statements.
Nuclear Waste — The federal government's program to construct a nuclear waste repository at Yucca Mountain, Nevada
was discontinued in 2010. Since 1998, the U.S. DOE has been in default of the federal government's obligations to begin accepting
spent nuclear fuel, or SNF, and high-level radioactive waste, or HLW, under the 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.
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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
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. While 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, the Company anticipates the cost of complying with these restrictions to be immaterial.
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, 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 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
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 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 working
with DNREC and other trustees to close out the assessment process.
Customers
NRG sells to a wide variety of customers. ERCOT accounted for 11% of NRG's total revenue in 2018. 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.
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Employees
As of December 31, 2018, NRG and its consolidated subsidiaries had 4,862 employees, approximately 26% of whom were
covered by U.S. bargaining agreements. During 2018, 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
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.
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.
NRG's financial performance may be impacted by price fluctuations in the retail and wholesale power and natural gas markets,
as well as fluctuations in 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.
While retail rates are generally designed to allow retail sellers of electricity and natural gas to pass through price fluctuations,
the Company may not be able to pass through all such fluctuations to customers. For example, the Company engages in some
sales of power at fixed prices. Additionally, increases in wholesale costs to retail customers may cause additional customer defaults
or increased customer attrition, or may be limited by regulatory rules.
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Such factors and the associated fluctuations in power prices have affected the Company's wholesale and retail profitability
in the past and will continue to do so in the future.
Some of NRG's businesses operate, wholly or partially, without long-term power sale agreements.
Some of NRG's businesses operate without long-term contracts. In retail, many of NRG’s customers are contracted for a
period of one year or less, and NRG may or may not hedge its retail power sales exposure, or may hedge in a manner that is not
effective at managing quantity or price risk in the retail market. In generation, 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 or purchase agreements, and without long-term load
obligations, NRG cannot be sure that it will be able to sell or purchase power at commercially attractive rates or that its generation
facilities will be able to operate profitably. This could lead to future impairments of the Company's property, plant and equipment,
the closing of certain of its facilities or the loss of retail customers, which could have a material adverse effect on the Company's
results of operations, financial condition or cash flows.
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'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. Its retail operations can likewise
be affected by changes in commodity costs. Grid operations depend on 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 generation facilities and to ensure that there is sufficient power produced to meet retail demand. As a result, the
Company’s wholesale generating facilities are 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. The Company’s retail operations are likewise subject to many of the same constraints.
NRG routinely hedges both its wholesale sales and purchases to support its retail load obligations. In order to hedge these
obligations, the Company may enter 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 or power supply arrangements may therefore require it to find alternative fuel sources at higher
costs, to find other sources of power to deliver to retail customers or other counterparties at a higher cost, or to pay damages to
counterparties for failure to deliver power or sell electricity or natural gas as contracted. Any such event could have a material
adverse effect on the Company's financial performance.
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NRG also buys significant quantities of electricity and fuel on a short-term or spot market basis. Prices sometimes rise or
fall 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. Retail rates may also not rise at the same rate, or may not rise
at all. This may have a material adverse effect on the Company's financial performance. Changes in market prices for electricity,
natural gas, coal and oil may result from the following:
• weather conditions;
•
•
•
•
•
•
•
•
•
seasonality;
demand for energy commodities and general economic conditions;
disruption or other constraints or inefficiencies of electricity, gas or coal transmission or transportation;
additional generating capacity;
availability and levels of storage and inventory for fuel stocks;
natural gas, crude oil, refined products and coal production levels;
changes in market liquidity;
federal, state and foreign governmental regulation and legislation; and
the creditworthiness and liquidity and willingness of fuel suppliers/transporters to do business with the Company.
NRG's plant operating characteristics and equipment, particularly at its coal-fired plants, often dictate the specific fuel quality
to be combusted. The availability and price of specific fuel qualities may vary due to supplier financial or operational disruptions,
transportation disruptions and force majeure. At times, coal of specific quality may not be available at any price, or the Company
may not be able to transport such coal to its facilities on a timely basis. In this case, the Company may not be able to run the coal
facility even if it would be profitable. Operating a coal facility with different quality coal can lead to emission or operating problems.
If the Company had sold forward the power from such a coal facility, it could be required to supply or purchase power from
alternate sources, perhaps at a loss. This could have a material adverse impact on the financial results of specific plants and on the
Company's results of operations.
Changes in the price of coal and natural gas could cause the Company to hold excess coal inventories and incur contract
termination costs.
Low natural gas prices can cause natural gas to be the more cost-competitive fuel compared to coal for generating electricity.
Because the Company enters into guaranteed supply contracts to provide for the amount of coal needed to operate its base load
coal-fired generating facilities, the Company may experience periods where it holds excess amounts of coal if fuel pricing results
in the Company reducing or idling coal-fired generating facilities. In addition, the Company may incur costs to terminate supply
contracts for coal in excess of its generating requirements.
Volatile power supply costs and demand for power could adversely affect the financial performance of NRG's retail businesses.
Although NRG is the primary provider of its retail businesses' wholesale electricity supply requirements, the retail businesses
purchase a significant portion of their supply requirements from third parties. As a result, financial performance depends on the
ability to obtain adequate supplies of electric generation from third parties at prices below the prices it charges its customers.
Consequently, the Company's earnings and cash flows could be adversely affected in any period in which the retail businesses'
wholesale electricity supply costs rise at a greater rate than the rates it charges to customers. The price of wholesale electricity
supply purchases associated with the retail businesses' energy commitments can be different than that reflected in the rates charged
to customers due to, among other factors:
•
•
•
•
•
varying supply procurement contracts used and the timing of entering into related contracts;
subsequent changes in the overall price of natural gas;
daily, monthly or seasonal fluctuations in the price of natural gas relative to the 12-month forward prices;
transmission constraints and the Company's ability to move power to its customers; and
changes in market heat rate (i.e., the relationship between power and natural gas prices).
The retail businesses' earnings and cash flows could also be adversely affected in any period in which its customers' actual
usage of electricity significantly varies from the forecasted usage, which could occur due to, among other factors, weather events,
competition and economic conditions.
27
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 and retail operations. The Company’s
risk management policies and hedging procedures may not mitigate risk as planned, and the Company may fail to fully or effectively
hedge its commodity supply and price risk. In addition, these activities, although intended to mitigate price volatility, expose the
Company to other risks. When the Company sells or buys power forward, it gives up the opportunity to buy or sell power at the
future price, 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.
There may be periods when NRG will not be able to meet its commitments under forward sale or purchase obligations at a
reasonable cost or at all.
The Company may sell 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.
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 and retail operations. These activities,
although intended to mitigate price volatility, expose the Company to other risks. When the Company sells or buys power forward,
it gives up the opportunity to buy or sell power at the future price, 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.
28
NRG may not have sufficient liquidity to hedge market risks effectively.
The Company is exposed to market risks through its retail and wholesale business, which involves the purchase of electricity
for resale, 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 or 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, or if retail customers use more power than expected, the
Company may be required to procure additional 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, as
well as retail sales of electricity.
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 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. New parties
may offer retail electricity bundled with other products or at prices that are below the Company’s rates.
Because many of the Company's facilities are older, 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.
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 retail sales or greater flexibility in the timing of their sale of
generation capacity and ancillary services than NRG does. Competitors may also have better access to subsidies or other out-of-
market payments that put NRG at a competitive disadvantage.
29
NRG's competitors may be able to respond more quickly to new laws or regulations or emerging technologies, or to devote
greater resources to marketing of retail power 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.
In addition, NRG provides plant operations and commercial services to a variety of third-parties. There is a risk that mistakes,
mis-operations, or actions taken by these third-parties could be attributed to NRG, including the risk of investigation or penalties
being assessed to NRG in connection with the services it offers, or that regulators could question whether NRG had the appropriate
safeguards in place.
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 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.
30
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.
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, chemicals 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 may rely on a single customer or a few customers to purchase all or a significant portion of a facility's output,
in some cases under long-term agreements that account for a substantial percentage of the anticipated revenue from a given facility.
The Company has also hedged a portion of its exposure to power price fluctuations through forward fixed price power sales and
natural gas price swap agreements. Counterparties to these agreements may breach or may be unable to perform their obligations.
NRG may not be able to enter into replacement agreements on terms as favorable as its existing agreements, or at all. If the
Company was unable to enter into replacement PPAs, the Company would sell its plants' power at market prices. If the Company
is unable to enter into replacement fuel or fuel transportation purchase agreements, NRG would seek to purchase the Company's
fuel requirements at market prices, exposing the Company to market price volatility and the risk that fuel and transportation may
not be available during certain periods at any price.
The failure of any supplier or customer to fulfill its contractual obligations to NRG could have a material adverse effect on
the Company's financial results. Consequently, the financial performance of the Company's facilities is dependent on the credit
quality of, and continued performance by, suppliers and customers.
NRG relies on power transmission and distribution facilities that it does not own or control and that are subject to transmission
constraints within a number of the Company's core regions.
NRG depends on transmission and distribution facilities owned and operated by others to deliver wholesale power sales and
retail power sales to its customers. If transmission or distribution is disrupted, including by force majeure events, or if the
transmission or distribution infrastructure is inadequate, NRG's ability to sell and deliver wholesale power may be adversely
impacted. The Company also cannot predict whether transmission or distribution 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 associated with wholesale power sales or purchases, or retail sales, particularly
where the Company’s load is not co-located with its retail sales obligations. If NRG were liable for such congestion costs, the
Company's financial results could be adversely affected.
Because NRG owns less than a majority of the ownership interests of some of its project investments, the Company cannot
exercise complete control over their operations.
NRG has limited control over the operation of some project investments and joint ventures because the Company's investments
are in projects where it beneficially owns less than a majority of the ownership interests. NRG seeks to exert a degree of influence
with respect to the management and operation of projects in which it owns less than a majority of the ownership interests by
negotiating to obtain positions on management committees or to receive certain limited governance rights, such as rights to veto
significant actions. However, the Company may not always succeed in such negotiations. NRG may be dependent on its co-
venturers to operate such projects. The Company's co-venturers may not have the level of experience, technical expertise, human
resources management and other attributes necessary to operate these projects optimally. The approval of co-venturers also may
be required for NRG to receive distributions of funds from projects or to transfer the Company's interest in projects.
31
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 and NRG may
be subject to trailing liabilities from businesses that it disposes of or that are inactive.
NRG may in the future make acquisitions or dispositions of businesses or assets, acquire or sell books of retail customers,
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 or customers, 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. In addition, NRG may be subject
to material trailing liabilities from disposed businesses such as Clearway Energy Inc., and its Renewables Platform. 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, 2018, approximately 26% 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 and the attractiveness of its retail products.
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. Technology, including distributed technology or changes in retail rate structures, may also have a material impact on the
Company’s ability to retain retail customers.
The Company may potentially be affected by emerging technologies that may over time affect change in capacity markets and
the energy industry overall with the inclusion of distributed generation and clean technology.
Some 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.
32
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, reduce the Company's
ability to sell retail power within certain states or to certain classes of retail customers; or restrict the Company’s marketing
practices, its ability to pass through costs to retail customers, or its ability to compete on favorable terms with competitors, including
the incumbent utility. Retail competition is regulated on a state-by-state level and is highly dependent on state laws, regulations
and policies, which could change at any moment.
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.
33
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 generation and competitive retail businesses rely on a competitive wholesale marketplace. The competitive wholesale
marketplace may be impacted 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, mandates to sell power below its cost of acquisition
and associated costs, as well as out-of-market payments to new or existing 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. The Company's retail
businesses may be materially impacted by rules or regulations that allow regulated utilities to participate in competitive retail
markets or own and operate facilities that could be provided by competitive market participants.
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.
34
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).
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 21, 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. 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.
Fluctuations in weather and other environmental conditions, including temperature and precipitation levels, 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.
35
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. NRG monitors water risk carefully. If it is determined that a
water supply risk exists that could impact projected generation levels at any plant risk mitigation efforts are identified and evaluated
for implementation.
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 2018 can be found in Item 1, Business — Operational Statistics. 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 which are subject to RGGI,
which is a regional cap and trade system for CO2. 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. The Company's retail businesses may be materially impacted by rules or regulations that allow regulated
utilities to participate in competitive retail markets or own and operate facilities that could be provided by competitive market
participants. 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. 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.
36
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:
•
•
•
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.
37
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.
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.
38
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Annual Report on Form 10-K of NRG Energy, Inc., or NRG or the Company, includes forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933, as amended, or Securities Act, and Section 21E of the Securities
Exchange Act of 1934, as amended, or Exchange Act. The words "believes," "projects," "anticipates," "plans," "expects," "intends,"
"estimates" and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve
known and unknown risks, uncertainties and other factors that may cause NRG's actual results, performance and achievements,
or industry results, to be materially different from any future results, performance or achievements expressed or implied by such
forward-looking statements. These factors, risks and uncertainties include the factors described under Item 1A — Risk Factors
Related to NRG Energy, Inc. and the following:
• 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;
• NRG's ability to obtain and maintain retail market share;
• 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, 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 achieve its strategy of regularly returning capital to stockholders;
• 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.
39
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.
40
Item 2 — Properties
Listed below are descriptions of NRG's interests in facilities, operations and/or projects owned or leased as of December 31,
2018. 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, 2018. The following table
summarizes NRG's power production and cogeneration facilities by region:
Name of Facility
Texas
Cedar Bayou
Cedar Bayou 4
Elbow Creek
Greens Bayou
Gregory
Limestone
Petra Nova Cogen
San Jacinto
South Texas Project(b)
T.H. Wharton
W.A. Parish
W.A. Parish
East/West
Agua Caliente
Arthur Kill
Astoria Turbines
Chalk Point
Connecticut Jet Power
Cottonwood(c)
Devon
Doga
Fisk
Gladstone
Indian River
Indian River
Ivanpah
Joliet(e)
Long Beach
Middletown
Midway-Sunset
Montville
Oswego
Powerton(e)
Sherbino Wind Farm
Stadiums
Sunrise
Vienna
Watson
Waukegan
Power Market
Plant Type
Primary Fuel
Location
Rated MW
Capacity
Net MW
Capacity(a)
%
Owned
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
WECC
NYISO
NYISO
PJM
ISO-NE
MISO
ISO-NE
PJM
PJM
PJM
CAISO
PJM
CAISO
ISO-NE
CAISO
ISO-NE
NYISO
PJM
ERCOT
CAISO
PJM
CAISO
PJM
Fossil
Fossil
Other
Fossil
Fossil
Fossil
Fossil
Fossil
Natural Gas
Natural Gas
Battery Storage
Natural Gas
Natural Gas
Coal
Natural Gas
Natural Gas
Nuclear
Uranium
Fossil
Fossil
Fossil
Natural Gas
Coal
Natural Gas
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
1,494
1,494
504
2
330
365
1,660
38
160
2,559
1,001
2,514
1,118
252
2
330
365
1,660
19
160
1,126
1,001
2,514
1,118
Total Texas
11,745
10,041
Natural Gas
Turkey
Renewable
Solar
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Natural Gas
Natural Gas
Natural Gas
Oil
Natural Gas
Oil
Oil
Coal
Coal
Oil
Renewable
Solar
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Natural Gas
Natural Gas
Oil
Natural Gas
Oil
Oil
Coal
Renewable Wind
Renewable
Solar
Fossil
Fossil
Fossil
Fossil
Natural Gas
Oil
Natural Gas
Coal
41
AZ
NY
NY
MD
CT
TX
CT
IL
AUS
DE
DE
CA
IL
CA
CT
CA
CT
NY
IL
TX
various
CA
MD
CA
IL
290
865
415
80
142
102
865
415
80
142
1,263
1,263
133
180
171
1,613
410
16
393
133
144
171
605
410
16
214
1,326
1,326
252
762
226
491
1,638
1,538
150
6
586
167
416
682
252
762
113
491
1,638
1,538
75
6
586
167
204
682
100.0
50.0
100.0
100.0
100.0
100.0
50.0
100.0
44.0
100.0
100.0
100.0
35.0
100.0
100.0
100.0
100.0
100.0
100.0
80.0
100.0
37.5
100.0
100.0
54.5
100.0
100.0
100.0
50.0
100.0
100.0
100.0
50.0
100.0
100.0
100.0
49.0
100.0
Name of Facility
Waukegan
Will County
Power Market
Plant Type
Primary Fuel
Location
PJM
PJM
Fossil
Fossil
Oil
Coal
IL
IL
Rated MW
Capacity
Net MW
Capacity(a)
%
Owned
101
510
101
510
100.0
100.0
Total East/West
14,822
13,011
Other
Residential solar
Renewable
Solar
various
Total Other
60
60
100.0
60
60
Total Continuing Operations, excluding Held for Sale
26,627
23,112
MISO
MISO
Held for Sale and Discontinued Operations
Bayou Cove(c)
Big Cajun I(c)
Big Cajun II(c)
Big Cajun II(c)
Big Cajun II(c)
Carlsbad(f)
Guam(d)
Sterlington(c)
MISO
MISO
MISO
CAISO
GPA
MISO
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Renewable
Fossil
Natural Gas
Natural Gas
Coal
Natural Gas
Coal
Natural Gas
Solar
Natural Gas
LA
LA
LA
LA
LA
CA
Guam
LA
Total Held for Sale and Discontinued Operations
225
430
580
540
588
528
26
176
3,093
225
430
580
540
341
528
26
176
2,846
100.0
100.0
100.0
100.0
58.0
100.0
100.0
100.0
Total Fleet
29,720
25,958
(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) Assets that are part of NRG's South Central Portfolio. The entire South Central Portfolio, including Cottonwood, was sold on February 4, 2019. NRG will
continue to operate the Cottonwood facility under a lease agreement through 2025
(d) Guam was classified as held for sale as of December 31, 2018. The sale was completed on February 20, 2019
(e) 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
(f) On February 6, 2018, the Company entered into an agreement with NRG Yield, Inc. and GIP to sell 100% of NRG's membership interests in Carlsbad Energy
Holdings LLC, which owns the Carlsbad project, a 528 MW natural gas-fired project in Carlsbad, California pursuant to the ROFO Agreement. The transaction
closed on February 27, 2019
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.
42
Item 3 — Legal Proceedings
See Item 15 — Note 21, Commitments and Contingencies, to the Consolidated Financial Statements for discussion of the
material legal proceedings to which NRG is a party.
Item 4 — Mine Safety Disclosures
Not applicable.
43
PART II
Item 5 — Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Market Information and Holders
NRG's authorized capital stock consists of 500,000,000 shares of 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 19, Stock-Based Compensation, to the Consolidated Financial Statements.
NRG had 283,650,039 shares outstanding as of December 31, 2018. As of January 31, 2019, there were 280,997,550 shares
outstanding, and there were 19,691 common stockholders of record.
NRG currently anticipates continuing to pay comparable cash dividends in the future.
Issuer Purchases of Equity Securities
In 2018, the Company's board of directors authorized the Company to repurchase $1.5 billion of its common stock. During
the year ended December 31, 2018, the Company repurchased a total of 35,234,664 shares under these programs for $1.25 billion,
and the remaining $250 million was repurchased by February 28, 2019. The average price paid per share for the $1.5 billion share
repurchase was $36.24. In addition, the Company's board of directors authorized in February 2019 an additional $1.0 billion share
repurchase program to be executed in 2019.
The table below sets forth the information with respect to purchases made by or on behalf of NRG or any "affiliated
purchaser" (as defined in Rule 10b-18(a)(3) under the Exchange Act), of NRG's common stock during the quarter ended
December 31, 2018.
For the three months ended
December 31, 2018
Month #1
(October 1, 2018 to October 31,
2018)
Month #2
(November 1, 2018 to November
30, 2018)
Month #3
(December 1, 2018 to December
31, 2018)(c)
Total at December 31, 2018
Total Number
of Shares
Purchased
Average Price
Paid per Share(a)
Total Number of Shares
Purchased as Part of Publicly
Announced Plans or Programs
Approximate Dollar Value of
Shares that May Yet Be
Purchased Under the Plans
or Programs(b)
— $
—
— $
500,000,000
1,964,808
$
38.59
1,964,808
$
424,174,905
4,725,163
6,689,971
$
$
36.87
37.38
4,725,163
$
6,689,971
249,951,196
(a) The average price paid per share excludes commissions of $0.01 per share paid in connection with the open market share repurchases
(b) Includes commissions of $0.01 per share paid in connection with the open market share repurchases
(c) Includes 486,618 of additional shares delivered upon settlement of an ASR agreement executed in September 2018
44
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, 2013 through December 31, 2018 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, 2013, 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-2013
Dec-2014
Dec-2015
Dec-2016
Dec-2017
Dec-2018
$
$
100.00
100.00
100.00
$
95.52
113.69
128.94
$
42.95
115.26
120.87
45.71
129.05
141.90
$
106.82
157.22
160.09
$
149.10
150.33
165.72
45
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, Acquisitions, Discontinued Operations and Dispositions.
Year Ended December 31,
2018
2017
2016
2015
2014
(In millions except ratios and per share data)
Net income/(loss) attributable to NRG — basic
$
Net income/(loss) attributable to NRG — diluted
Dividends declared per common share
$ (6.79)
$ (2.22)
$ (19.46)
$
(2.22)
0.24
(19.46)
0.58
Statement of income data:
Total operating revenues
Total operating costs and other expenses (a)
Impairment losses (b)
Operating income/(loss)
Impairment losses on investments
Income/(loss) from continuing operations, net
(Loss)/income from discontinued operations, net
Net income/(loss) attributable to NRG Energy, Inc.
Common share data:
Basic shares outstanding — average
Diluted shares outstanding — average
Shares outstanding — end of year
Per share data:
Book value
Business metrics:
Cash flow from operations
Liquidity position (c)
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
$ 9,478
$ 9,074
$ 8,915
$ 10,842
(9,208)
(11,010)
(8,929)
(99)
982
(15)
460
(8,953)
(1,534)
(741)
(79)
(1,345)
(192)
268
$
(992)
$ (2,153)
$
304
308
284
0.88
0.87
0.12
317
317
317
(6.79)
0.12
6.20
(483)
33
(268)
(956)
65
(774)
316
316
315
(4,823)
(4,347)
(40)
(6,379)
(57)
$ (6,382)
$
329
329
314
$ 11,387
(11,606)
(5)
537
—
(223)
355
134
334
339
337
0.23
0.23
0.54
$ (4.35)
$
$ 14.09
$ 17.29
$
34.68
$ 1,377
$ 1,610
$ 1,908
$ 1,419
$
1,620
1,977
2,760
1,768
2,102
(21.72)% (109.40)% (17.41)% (117.45)%
126.12 %
81.40 %
68.26 %
63.96 %
2,136
1.15%
46.61%
$ 3,600
$ 4,437
$ 6,747
$ 8,231
$
9,454
2,398
3,048
10,628
3,354
5,974
23,355
4,736
7,877
30,716
5,215
8,283
33,738
5,732
11,823
41,551
6,521
9,384
10,071
10,867
11,184
$ (1,234)
$ 1,968
$ 4,446
$ 5,434
$ 11,695
(b)
Includes goodwill impairment as described in Item 15 - Note 10, 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 $33 million, $37 million and $2 million as of
December 31, 2018, 2017 and 2016, 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
46
The following table provides the details of NRG's operating revenues:
Energy revenue
Capacity revenue
Retail revenue
Mark-to-market for economic hedging activities
Contract amortization
Other revenues
Corporate/Eliminations
Total operating revenues(a)
2018
2,677
670
7,110
(209)
—
287
(1,057)
9,478
$
$
$
$
(a) Inter-segment sales and net derivative gains and losses included in operating revenues
2017
2015
$
Year Ended December 31,
2016
(In millions)
3,243
$
642
6,332
(566)
(1)
313
(1,048)
8,915
2,725
618
6,374
33
(1)
235
(910)
9,074
$
$
4,131
781
6,907
(138)
(1)
202
(1,040)
10,842
$
$
2014
4,215
690
7,371
684
1
313
(1,887)
11,387
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. These amounts are amortized into revenue
over the term of the underlying contracts based on contracted volumes.
Other revenues 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 third party and 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.
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.
47
Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations
The discussion and analysis below has been organized as follows:
• Executive Summary, including the business environment in which NRG Energy Inc., or NRG or the Company, operates,
a discussion of regulation, weather, competition and other factors that affect the business, Transformation Plan update,
and other 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, 2018, 2017, and 2016, and also refer to Item 1
to this Form 10-K for more detailed discussion about the Company's business.
As further described in Note 3, Acquisitions, Discontinued Operations and Dispositions, the Company is treating the
following businesses as discontinued operations, which have been recast to present in the corporate segment:
South Central Portfolio
•
• NRG Yield, Inc. and its Renewables Platform
• Carlsbad
• GenOn
Executive Summary
NRG is an energy company built on dynamic retail brands with diverse generation assets. NRG brings the power of energy
to consumers 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 sells energy, services, and innovative,
sustainable products and services directly to retail customers under the names "NRG" and "Reliant" and other brand names owned
by NRG supported by approximately 23,000(a) MW of generation as of December 31, 2018.
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 2018 and for the future medium term include:
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. 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 2018, average natural gas prices at Henry Hub
was 1.0% lower than in 2017.
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.
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.
(a) excluding discontinued operations and held for sale
48
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. An increase in supply cost volatility in the competitive retail markets may result in smaller companies
choosing to exit the market, which may result in further consolidation in the competitive retail space. 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, 2018, 2017,
and 2016. Power prices were higher for the year ended December 31, 2018 as compared to the same period in 2017 and 2016.
ERCOT power prices were higher primarily due to the continued effect of lower reserve margins as a result of asset retirements
in the region. Power prices in East region increased for the year ended December 31, 2018 as compared to the same period in
2017 and 2016 primarily driven by higher winter demand and higher natural gas prices in the fourth quarter of 2018.
Region
Texas (a)
Average On-Peak Power Price ($/MWh)
Year Ended December 31
2017
2016
2018
2018 vs 2017
Change %
2017 vs 2016
Change %
ERCOT - Houston(a)
ERCOT - North(a)
$
37.29
$
36.26
33.95
$
25.86
East/West
MISO - Louisiana Hub(b)
NY J/NYC(b)
NEPOOL(b)
COMED (PJM)(b)
PJM West Hub(b)
CAISO - SP15(b)
43.70
47.19
49.96
34.60
41.66
47.33
40.02
38.34
37.18
32.46
34.14
36.48
26.91
24.53
34.30
35.29
35.05
32.11
33.79
31.17
(a) Average on-peak power prices based on real time settlement prices as published by the respective ISOs
(b) Average on-peak power prices based on day ahead settlement prices as published by the respective ISOs
10%
40%
9%
23%
34%
7%
22%
30%
26%
5%
17%
9%
6%
1%
1%
17%
The following table summarizes average realized power prices for each region in which NRG operates for the years ended
December 31, 2018, 2017, and 2016, which reflects the impact of settled hedges.
Region
Texas
East/West
Average Realized Power Price ($/MWh)
Year Ended December 31
2017
2016
2018
2018 vs 2017
Change %
2017 vs 2016
Change %
$
$
37.12
43.70
$
33.45
46.48
40.49
47.14
11 %
(6)%
(17)%
(1)%
The average realized power prices for December 31, 2018 as compared to the same period in 2017, increased in Texas as
a result of higher power prices, and decreased in East/West as a result of the roll off of hedges. The average realized power
prices for December 31, 2017 as compared to the same period in 2016 decreased in both Texas and East/West as a result of the
roll off of hedges.
Clean Infrastructure Development — Policy mechanisms at the state and federal level including production and investment
tax credits, cash grants, loan guarantees, accelerated depreciation tax benefits, RPS, and carbon trading plans, have supported and
continue to support the development of renewable generation, demand-side and smart grid, and other clean infrastructure
technologies. In addition, the costs associated with the development of clean infrastructure, such as wind and solar generating
facilities, continues to decline. These factors continue to drive increases in the development of clean infrastructure in the markets
where the Company participates, which may impact the ability of the Company's generating facilities to participate in those markets.
According to ERCOT, Inc., more than 30% of 2018 energy consumption in the ERCOT market was generated from carbon-free
resources with wind power contributing 19%. Certainly, subsidies and incentives have contributed to the increase in renewable
power sources, but it is also true that customer awareness/preferences have shifted toward sustainable solutions. Alternatively,
increased demand for sustainable energy products from both residential and commercial consumers creates opportunities for
diversified product offerings in competitive retail markets.
49
Digitization and Customization — The electric industry is experiencing major technology changes in the way power is
distributed and used by end-use customers. The electric grid is shifting from a centralized analog system, where power is generated
from limited sources and flows in one direction, to a decentralized multidirectional system, where power can be generated from
a number of distributed resources and stored or dispatched on an as-needed basis. In addition, consumers are seeking new ways
to engage with their power providers. Technologies like smart thermostats, appliances and electric vehicles are giving individuals
more choice and control over their electricity usage.
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 and 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.
Other Factors — A number of other factors significantly influence the level and volatility of prices for energy commodities
and related derivative products for NRG's business. These factors include:
•
•
•
•
•
•
•
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
These factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects
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 23, Environmental Matters, to the Consolidated Financial Statements and Item 1— Business, Environmental
Matters, section. Details of regulatory matters are presented in Item 15 — Note 22, Regulatory Matters, to the Consolidated
Financial Statements and Item 1— Business, Regulatory Matters, section. Details of legal proceedings are presented in
Item 15 — Note 21, 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.
50
Transformation Plan
NRG is well underway in executing its Transformation Plan. The Company expects to fully implement the Transformation
Plan by the end of 2020 with a significant portion completed in 2018. The three-part, three-year plan is comprised of the following
targets and the Company's achievements towards such targets are as follows:
Operations and Cost Excellence
Recurring cost savings and margin enhancement of $1,065 million, which consists of $590 million of cumulative 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. The Company realized
annual cost savings of $532 million and $32 million of margin enhancements during the year ended December 31, 2018 and is on
track to realize $590 million of cost savings and $135 million of margin enhancements in 2019.
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. By December 31, 2018, NRG has realized $333 million of non-recurring
working capital improvements and $194 million of one-time costs to achieve. The Company expects to incur approximately $95
million of one-time costs to achieve in 2019.
Portfolio Optimization
Targeted and completed $3.0 billion of asset sale cash proceeds received through February 28, 2019, as described below:
• In 2017, NRG executed asset sales of 322 MW for aggregate cash of $150 million, which includes sales to NRG Yield, Inc.
and the sale of Minnesota wind projects to third parties
• On March 30, 2018, the Company completed the sale of 100% of its ownership interest in Buckthorn Solar to NRG Yield,
Inc. for cash consideration of approximately $42 million
• On August 1, 2018, the Company completed the sale of 100% of its ownership interests in BETM to Diamond Energy
Trading and Marketing, LLC for $70 million, excluding working capital adjustments. The sale also resulted in the release
and return of approximately $119 million of letters of credit, $32 million of parent guarantees, and $4 million of net cash
collateral to NRG
• On August 31, 2018, the Company completed the sale of its interest in NRG Yield, Inc. and its Renewables Platform to GIP,
for approximately $1.348 billion in cash proceeds
• On November 1, 2018, the Company offered to Clearway Energy, Inc. its ownership interest in Agua Caliente Borrower 1,
LLC, for approximately $120 million, which owns a 35% interest in AGua Caliente, a 290 MW utility scale solar project.
The offer expired on January 31, 2019 with no action taken by Clearway Energy, Inc. As a result of this expiration, the
Company has removed this asset from the target asset sale cash proceeds under the Transformation Plan.
• During the twelve months ended December 31, 2018, the Company completed the sale of various other assets for
approximately $28 million
• On February 4, 2019, NRG sold the South Central portfolio, a 3,555 MW portfolio of generation assets, for cash consideration
of $1 billion, excluding working capital and other adjustments
• On February 20, 2019, NRG completed the sale of Guam for cash consideration of approximately $8 million
• On February 27, 2019, NRG sold the Carlsbad project, a 528 MW natural gas-fired power plant, for cash consideration of
$387 million, excluding working capital and other adjustments
Capital Structure and Allocation
As of December 31, 2018, the Company achieved the previously announced target of reducing consolidated corporate debt
to 3.0x net debt / adjusted EBITDA(a) credit ratio on a pro forma basis that includes the South Central Portfolio sale proceeds. To
achieve this ratio, the Company completed the following:
• Reduction of $9.2 billion in non-recourse debt related to the sale of NRG Yield, Inc. and the Renewable Platform, which
includes the debt for Carlsbad Energy Center, as well as the impact of deconsolidation of Agua Caliente and Ivanpah
• The Company has completed its targeted $640 million of debt reduction through the redemption of $485 million of its
outstanding 6.250% senior notes due 2022 and the Term Loan prepayment of $155 million. The annualized interest
savings related to these activities to date totals $37 million
In 2018, the Company's board of directors authorized the Company to repurchase $1.5 billion of its common stock. As of
February 28, 2019, the Company completed $1.5 billion of repurchases at an average price of $36.24 per share. In addition, the
Company's board of directors authorized in February 2019 an additional $1 billion share repurchase program to be executed in
2019.
(a) adjusted EBITDA as defined per the Senior Credit Facility
51
Other Significant Events
The following additional significant events occurred during 2018:
XOOM Energy Acquisition
• On June 1, 2018, the Company completed the acquisition of XOOM Energy, LLC, an electricity and natural gas retailer
operating in 19 states, Washington, D.C. and Canada for approximately $213 million in cash. See Note 3, Acquisitions,
Discontinued Operations and Dispositions for further discussion on purchase price allocation. The acquisition increased
NRG's retail portfolio by approximately 300,000 customers.
Agua Caliente and Ivanpah Deconsolidation
• During the third quarter of 2018, the Company, recognized a gain of $8 million on the deconsolidation and subsequent
recognition of its 35% interest in Agua Caliente as an equity method investment, as discussed in more detail in Note 3
Acquisitions, Discontinued Operations and Dispositions
During the second quarter of 2018, the Company, recognized a loss of $22 million on the deconsolidation and subsequent
recognition of its 54.6% interest in Ivanpah as an equity method investment, as discussed in more detail in Note 15,
Investments Accounted for by the Equity Method and Variable Interest Entities.
Financing Activities
• On March 21, 2018, the Company repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis
points to LIBOR plus 1.75% and reducing the LIBOR floor to 0.00%. As a result of the repricing, the Company expects
approximately $47 million in interest savings over the remaining life of the loan.
• On May 24, 2018, the Company issued $575 million in aggregate principal amount at par of 2.75% convertible senior
notes due 2048, as discussed in more detail in Note 11, Debt and Capital Leases.
• During the year ended December 31, 2018, the Company completed senior note repurchases of $1,061million in aggregate
principal of its senior notes for $1,106 million, including accrued interest, as discussed in more detail in Note 11, Debt
and Capital Leases.
• The annualized interest savings related to these activities to date totals $20 million
52
Consolidated Results of Operations for the years ended December 31, 2018 and 2017
The following table provides selected financial information for the Company:
(in millions except otherwise noted)
Operating Revenues
Energy revenue (a)
Capacity revenue (a)
Retail revenue
Mark-to-market for economic hedging activities
Contract amortization
Other revenues (b)
Total operating revenues
Operating Costs and Expenses
Cost of sales (b)
Mark-to-market for economic hedging activities
Contract and emissions credit amortization (c)
Operations and maintenance
Other cost of operations
Total cost of operations
Depreciation and amortization
Impairment losses
Selling, general and administrative
Reorganization costs
Development costs
Total operating costs and expenses
Other income - affiliate
Gain on sale of assets
Operating Income/(Loss)
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates
Impairment losses on investments
Other income, net
Net loss on debt extinguishment
Interest expense
Total other expenses
Income/(Loss) from Continuing Operations Before Income Taxes
Income tax expense/(benefit)
Income/(Loss) from Continuing Operations
Loss from discontinued operations, net of income tax
Net Income/(Loss)
Less: Net loss attributable to noncontrolling interests and redeemable
noncontrolling interests
Net Income/(Loss) Attributable to NRG Energy, Inc.
Business Metrics
Average natural gas price — Henry Hub ($/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
53
Year Ended December 31,
2018
2017
Change
1,548
670
7,105
(130)
—
285
9,478
5,878
(144)
27
1,083
264
7,108
421
99
799
90
11
8,528
—
32
982
9
(15)
18
(44)
(483)
(515)
467
7
460
(192)
268
—
268
3.09
$
$
1,636
612
6,378
252
(1)
197
9,074
5,432
46
34
1,097
277
6,886
596
1,534
836
44
22
9,918
87
16
(741)
(14)
(79)
51
(49)
(557)
(648)
(1,389)
(44)
(1,345)
(992)
(2,337)
(88)
58
727
(382)
1
88
404
(446)
190
7
14
13
(222)
175
1,435
37
(46)
11
1,390
(87)
16
1,723
23
64
(33)
5
74
133
1,856
51
1,805
800
2,605
(184)
(2,153) $
184
2,421
3.11
(1)%
$
$
$
$
$
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, 2018 and 2017:
(In millions except otherwise noted)
Retail
Texas
Year Ended December 31, 2018
Generation
East/West/
Other(a)(b)
Subtotal
Corporate/
Eliminations
Total
Energy revenue
Capacity revenue
Retail revenue
Mark-to-market for economic hedging
activities
Other revenue
Operating revenue
Cost of fuel
Other costs of sales(c)
Mark-to-market for economic hedging
activities
Contract and emission credit amortization
Gross margin
Less: Mark-to-market for economic hedging
activities, net
Less: Contract and emission credit
amortization, net
Economic gross margin
Business Metrics
MWh sold (thousands)
MWh generated (thousands)
$
— $
1,585
$
1,092
$
2,677
$
(1,129) $
—
7,110
(7)
—
7,103
(23)
(5,285)
260
—
1
—
(174)
84
1,496
(734)
(133)
2
(26)
669
—
(28)
203
1,936
(557)
(275)
(39)
(1)
670
—
(202)
287
3,432
(1,291)
(408)
(37)
(27)
—
(5)
79
(2)
(1,057)
(4)
1,133
(79)
—
1,548
670
7,105
(130)
285
9,478
(1,318)
(4,560)
144
(27)
$
$
2,055
$
605
$
1,064
$
1,669
$
(7) $
3,717
253
—
1,802
$
(172)
(26)
803
42,701
38,214
$
$
$
(67)
(1)
(239)
(27)
—
—
1,132
$
1,935
$
(7) $
14
(27)
3,730
24,988
21,089
(a) Includes International, Renewables, and Generation eliminations
(b) Includes Agua, BETM and Ivanpah which were sold or deconsolidated as of August, July and April 2018, respectively
(c) Includes purchased energy, capacity and emissions credits
54
(In millions except otherwise noted)
Retail
Texas
East/West/
Other(a)
Subtotal
Corporate/
Eliminations
Total
Year Ended December 31, 2017
Generation
$
— $
1,427
$
1,298
$
2,725
$
(1,089) $
Energy revenue
Capacity revenue
Retail revenue
Mark-to-market for economic hedging
activities
Contract amortization
Other revenue
Operating revenue
Cost of fuel
Other costs of sales(b)
Mark-to-market for economic hedging
activities
Contract and emission credit amortization
Gross margin
Less: Mark-to-market for economic hedging
activities, net
Less: Contract and emission credit
amortization, net
Economic gross margin
$
$
Business Metrics
MWh sold (thousands)
MWh generated (thousands)
—
6,374
(4)
(1)
—
6,369
(13)
(4,759)
181
—
22
—
94
—
35
1,578
(732)
(137)
(21)
(30)
596
—
(57)
—
200
2,037
(542)
(370)
13
(4)
618
—
37
—
235
3,615
(1,274)
(507)
(8)
(34)
(6)
4
219
—
(38)
(910)
1
1,120
(219)
—
1,636
612
6,378
252
(1)
197
9,074
(1,286)
(4,146)
(46)
(34)
1,778
$
658
$
1,134
$
1,792
$
(8) $
3,562
177
(1)
73
(30)
(44)
(4)
29
(34)
—
—
1,602
$
615
$
1,182
$
1,797
$
(8) $
206
(35)
3,391
42,662
38,694
27,923
21,338
(a) Includes International, Renewables, and Generation eliminations
(b) Includes purchased energy, capacity and emissions credits
The table below represents the weather metrics for 2018 and 2017:
Years ended
December 31,
Quarters ended
December 31,
Quarters ended
September 30,
Quarters ended
June 30,
Quarters ended
March 31,
Weather Metrics
Texas
East/West/
Other
Texas
East/West/
Other
Texas
East/West/
Other
Texas
East/West/
Other
Texas
East/West/
Other
2018
CDDs(a)
HDDs(a)
2017
CDDs
HDDs
10 year average
CDDs
HDDs
3,130
1,874
3,068
1,270
3,023
1,728
1,213
3,393
1,155
3,198
1,059
3,459
228
815
311
665
264
695
74
1,214
84
1,157
69
1,214
1,657
1
1,568
1
1,654
3
856
26
770
33
714
40
1,101
90
966
32
1,004
56
265
425
281
380
259
429
144
968
223
572
101
974
18
1,728
20
1,628
17
1,776
(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.
55
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
Operating revenue (a)
Cost of sales (b)
Mark-to-market for economic hedging activities
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) - Texas
Mass electricity sales volume (GWh) - All other regions
C&I electricity sales volume (GWh) All regions (b)
Natural gas sales volumes (MDth)
Average Retail Mass customer count (in thousands)
Ending Retail Mass customer count (in thousands)
$
$
$
Years ended December 31,
2018
2017
$
$
$
6,775
174
161
(7)
—
7,103
(5,308)
260
2,055
253
—
1,802
37,846
7,968
21,176
11,253
3,063
3,320
6,104
187
83
(4)
(1)
6,369
(4,772)
181
1,778
177
(1)
1,602
36,169
6,221
20,400
3,212
2,862
2,876
(a)
(b)
Includes intercompany sales of $5 million and $5 million in 2018 and 2017, respectively, representing sales from Retail to the Texas region
Includes intercompany purchases of $1,163 million and $1,090 million in 2018 and 2017, respectively
Retail gross margin increased $277 million and retail economic gross margin increased $200 million for the year ended
December 31, 2018, compared to the same period in 2017, due to:
Higher gross margin driven by margin enhancement initiatives enhancing customer product, retention, term
and mix of $3.30 per MWh, or $208 million partially offset by higher supply costs due to increased power
prices in ERCOT of $2.40 MWh, or $150 million.
Higher gross margin due to higher volumes from net higher average customer counts primarily driven by
XOOM acquisition in June 2018
Higher gross margin from the favorable impact of weather due to $44 million from an increase in load in 2018
of 1,893,000 MWh partially offset by an unfavorable impact of $14 million from selling back additional
excess supply in 2018 as well as $16 million due to the impacts of Hurricane Harvey in 2017
Higher gross margin due to an increase in capacity revenues from the business solutions unit mainly due to
approximately 1,600 additional MWs sold and margin enhancements from the sale of additional capacity of
$11 million
Increase 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
Increase in gross margin
(In millions)
$
$
$
58
60
46
36
200
76
1
277
56
Generation gross margin and economic gross margin
Generation gross margin decreased $123 million and generation economic gross margin increased $138 million, both of
which include intercompany sales, during the year ended December 31, 2018, compared to the same period in 2017.
The tables below describe the change in Generation gross margin and generation economic gross margin:
Texas Region
Higher gross margin due to a 11% increase in average realized prices
Higher gross margin from sales of NOx emission credits
Higher gross margin from commercial optimization activities
Higher gross margin due to margin enhancement initiatives from reduced fuel supply costs
Lower gross margin driven by planned outages for both units at STP in 2018 as compared to a single unit
planned outage in 2017
Lower gross margin due to an increase in tolling purchases in 2018 as a result of increased demand and the
cancellation of the Greens Bayou RMR agreement in 2017
Other
Increase 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
East/West Region
Lower gross margin primarily due to Ivanpah and Agua Caliente being deconsolidated in April 2018 and
August 2018, respectively
Lower gross margin driven by a 26% decrease in realized capacity pricing in New York and expiration of the
Long Beach capacity toll in July 2017
Lower gross margin mainly due to an 11% decrease in average realized prices, primarily at Midwest Generation
Lower gross margin due to decreased load contract volumes coupled with lower prices
Lower gross margin at Sunrise in 2018 due to planned major maintenance activities that extended into a forced
outage.
Higher gross margin due to a 32% increase in PJM capacity prices and a 51% increase in NEISO capacity
prices
Higher gross margin from commercial optimization activities
Higher gross margin due to 2017 lower cost of market adjustment for fuel inventory
Higher gross margin as a result of trading activity at BETM
Higher gross margin due to margin enhancement initiatives from reduced fuel supply costs
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
Increase in contract and emission credit amortization
Decrease in gross margin
(In millions)
153
$
36
5
3
(9)
(9)
9
188
(245)
4
(53)
$
$
(In millions)
$
(123)
(51)
(42)
(29)
(17)
132
35
31
8
4
2
(50)
(23)
3
(70)
$
$
57
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 decreased by $192 million during the year ended December 31, 2018, compared to the
same period in 2017.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows:
Year Ended December 31, 2018
Generation
Retail
Texas
East/West/
Other
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)/gains in operating revenues
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses 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/(losses) in operating costs and
expenses
$
$
$
(2) $
32
$
(3) $
(104) $
(77)
(5)
(206)
(25)
183
(7) $
(174) $
(28) $
79
$
(81) $
(10)
351
260
$
(6) $
(13) $
104
$
—
8
2
—
(26)
—
(183)
$
(39) $
(79) $
(53)
(130)
4
(10)
150
144
(a) Represents the elimination of the intercompany activity between Retail and Generation
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows:
Year Ended December 31, 2017
Generation
Retail
Texas
East/West/
Other
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)/gains 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 gains/(losses) on open positions related to
economic hedges
Total mark-to-market gains/(losses) in operating costs and
expenses
$
$
$
$
(2) $
140
$
(72) $
64
$
(2)
(4) $
(46)
15
94
$
(57) $
155
219
$
130
122
252
(1) $
(17) $
(1) $
(64) $
(83)
182
(4)
14
(155)
37
181
$
(21) $
13
$
(219) $
(46)
(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.
58
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, 2018 the $130 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, as well as
a decrease in value of open positions as a result of losses on ERCOT heat rate positions due to heat rate expansion. The $144
million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of
open positions as a result of increases in ERCOT heat rate, partially offset by the reversal of acquired gain positions.
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, 2018 and 2017. 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.
(In millions)
Trading gains/(losses)
Realized
Unrealized
Total trading gains
Year ended December 31,
2018
2017
$
$
77
17
94
$
$
43
(11)
32
59
Operations and Maintenance Expense
Generation
Retail
Texas
East/West/
Other
Corporate
Eliminations
Total
Year Ended December 31, 2018
Year Ended December 31, 2017
$
$
209
224
$
$
437
387
$
$
440
458
$
$
3
31
$
$
(6) $
(3) $
1,083
1,097
Operations and maintenance expenses decreased by $14 million for the year ended December 31, 2018, compared to the
same period in 2017, due to the following:
Decrease in operations and maintenance due to cost efficiencies as a result of the Transformation Plan
$
Decrease in operations and maintenance due to the deconsolidation of Ivanpah and Agua Caliente in April 2018
and August 2018, respectively
Increase in major maintenance due to planned outages of $19 million in Texas and planned outages for both
units at STP in 2018 as compared to a planned outage for a single unit in 2017 of $22 million
2018 payments in settlement of certain legal matters
Increase in technology and personnel costs for customer operations and retention related to margin
enhancement
Increase in deactivation cost primarily at Dunkirk
Increase in costs due to the XOOM acquisition
Other
$
(In millions)
(70)
(31)
41
13
11
8
7
7
(14)
(a) Approximately $162 million of additional cost savings were achieved in the year ended December 31, 2017, as compared to the year ended December 31,
2016, as the savings became permanent through the Transformation Plan
Other Cost of Operations
Year Ended December 31, 2018
Year Ended December 31, 2017
Generation
Retail
Texas
East/West/
Other
(In millions)
Total
$
$
109
99
$
$
76
81
$
$
79
97
$
$
264
277
Other cost of operations, decreased by $13 million for the year ended December 31, 2018, compared to the same period in
2017.
Decrease due to lower in accretion expense in 2018 at Huntley as a result of a cost estimate increase in 2017
Decrease in property taxes as a result of the Transformation Plan
Other
(In millions)
$
$
(8)
(4)
(1)
(13)
60
Depreciation and Amortization
Year Ended December 31, 2018
Year Ended December 31, 2017
$
$
116
110
$
$
(In millions)
272
$
454
$
33
32
$
$
421
596
Retail
Generation
Corporate
Total
Depreciation and amortization expense decreased by $175 million for the year ended December 31, 2018, compared to the
same period in 2017, primarily due to impairments of $1,534 million in 2017 and the deconsolidation of Ivanpah and Agua Caliente
in 2018.
Impairment Losses
For the year ended December 31, 2018, the Company recorded impairment losses of $99 million related to various facilities
as further described in Item 15 — Note 9, Asset Impairments, to the Consolidated Financial Statements.
In 2017, the Company recorded impairment losses of $1,534 million related to various facilities, as well as goodwill for its
Texas reporting units, as further described in Item 15 — Note 9, Asset Impairments and Note 10, Goodwill and Other Intangibles,
to the Consolidated Financial Statements.
Selling, General and Administrative Expenses
Year Ended December 31, 2018
Year Ended December 31, 2017
$
$
538
452
$
$
(In millions)
212
215
$
$
49
169
$
$
799
836
Retail
Generation
Corporate
Total
Selling, general and administrative expenses decreased by $37 million for the year ended December 31, 2018 compared to
the same period in 2017.
Decrease in general and administrative expense from cost initiatives for the Transformation Plan(a)
Prior year fees associated with advisors engaged to assist the Company in its strategic review in 2017
Increase in selling and marketing expenses associated with costs incurred for margin enhancement
initiatives
Increase in commission expense associated with selling initiatives
Increase in costs due to the XOOM acquisition
Increase in bad debt expense primarily from increased usage due to weather
Increase due to additional litigation in 2018
Other
(In millions)
$
(164)
(22)
51
32
32
18
10
6
(37)
$
(a) Approximately $98 million of additional cost savings were achieved in the year ended December 31, 2017, as compared to the year ended
December 31, 2016, as the savings became permanent through the Transformation Plan
61
Reorganization Costs
Reorganization costs, primarily related to severance and contract modifications, increased by $46 million for the year ended
December 31, 2018, as compared to the same period in 2017 as the Company continued with 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 June 14, 2017, the date of deconsolidation of $87 million.
Gain on Sale of Assets
Gain on sale of assets for the year ended December 31, 2018, consists primarily of the gain on the sale of BETM and Canal
3, while the gain on sale of assets for the year ended December 31, 2017, represents a gain on the sale of land.
Impairment Losses on Investments
For the year ended December 31, 2018, the Company recorded other-than-temporary impairment losses of $15 million,
compared to $79 million in other-than-temporary impairment losses recorded in the same period in 2017, as further described in
Item 15 — Note 9, Asset Impairments, to the Consolidated Financial Statements.
Loss on Debt Extinguishment
A loss on debt extinguishment of $44 million was recorded for the year ended December 31, 2018, primarily driven by the
redemption of Senior Notes, due 2022 at a price above par value.
A loss on debt extinguishment of $49 million was recorded for the year ended December 31, 2017, driven by the repurchase
of 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.
62
Income Tax Expense
For the year ended December 31, 2018, NRG recorded income tax expense of $7 million on pre-tax income of $467 million.
For the same period in 2017, NRG recorded income tax benefit of $44 million on a pre-tax loss of $1,389 million. The effective
tax rate was 1.5% and 3.2% for the years ended December 31, 2018 and 2017, respectively.
For the year ended December 31, 2018, NRG's overall effective tax rate was different than the federal statutory tax rate of
21% primarily due to a tax benefit for the change in valuation allowance, the generation of PTCs from various wind facilities, and
establishment of the previously sequestered ATM credit receivable, partially offset by current state tax expense.
Income/(Loss) from continuing operations before income taxes
$
467
$
(1,389)
Year Ended December 31,
2018
2017
(In millions
except as otherwise stated)
Tax at federal statutory tax rate
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
Permanent differences
Production tax credits
Recognition of uncertain tax benefits
Alternative minimum tax ("AMT") refundable credit
Other
Income tax expense/(benefit)
Effective income tax rate
98
18
—
—
—
(106)
—
—
7
(7)
1
(4)
—
7
1.5%
$
(486)
19
2
665
(660)
455
(5)
30
—
(8)
(5)
(64)
13
(44)
3.2%
$
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.
Income/(Loss) from Discontinued Operations, Net of Income Tax
(In millions)
South Central
Yield Renewables Platform & Carlsbad
Genon
Loss from discontinued operations, net of tax
Year Ended December 31,
2018
2017
Change
$
$
66
(292)
34
(192) $
$
87
(290)
(789)
(992) $
(21)
(2)
823
800
For the year ended December 31, 2018, NRG recorded a loss from discontinued operations, net of income tax of $192
million, a decrease of $800 million in losses from discontinued operations, net of income tax for the same period in 2017, as
further described in Item 15 — Note 3 Acquisitions, Discontinued Operations and Dispositions .
63
Net loss attributable to noncontrolling interests and redeemable noncontrolling interests
Net loss attributable to noncontrolling interests and redeemable noncontrolling interests was $0 million for the year ended
December 31, 2018, compared to $184 million for the year ended December 31, 2017. For the years ended December 31, 2018,
and 2017, the net losses attributable to noncontrolling interests primarily reflect losses allocated to tax equity investors using the
hypothetical liquidation at book value, or HLBV, method, offset in whole and in part by NRG Yield, Inc.'s share of income for the
periods, respectively. As a result of the disposition of NRG Yield Inc. and its Renewables Platform, the Company did not have
material actuals in 2018 nor does it anticipate material NCI in the future.
64
Consolidated Results of Operations for the years ended December 31, 2017 and 2016
The following table provides selected financial information for the Company:
(In millions except otherwise noted)
Operating Revenues
Energy revenue (a)
Capacity revenue (a)
Retail revenue
Mark-to-market for economic hedging activities
Contract amortization
Other revenues (b)
Total operating revenues
Operating Costs and Expenses
Cost of sales (a)
Mark-to-market for economic hedging activities
Contract and emissions credit amortization (c)
Operations and maintenance
Other cost of operations
Total cost of operations
Depreciation and amortization
Impairment losses
Selling, general and administrative
Reorganization costs
Development costs
Total operating costs and expenses
Other income - affiliate
Gain/(loss) on sale of assets
Operating (Loss)/Income
Other Income/(Expense)
Equity in losses of unconsolidated affiliates
Impairment losses on investments
Other income, net
Loss on debt extinguishment
Interest expense
Total other expense
Loss from Continuing Operations Before Income Taxes
Income tax (benefit)/expense
Net Loss from Continuing Operations
(Loss)/income from discontinued operations, net of tax
Net Loss
Less: Net loss attributable to noncontrolling interests and redeemable
noncontrolling interests
Net Loss Attributable to NRG Energy, Inc.
Business Metrics
Average natural gas price — Henry Hub ($/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
65
Year Ended December 31,
2017
2016
Change
$
1,636
612
6,378
252
(1)
197
9,074
5,432
46
34
1,097
277
6,886
596
1,534
836
44
22
9,918
87
16
(741)
(14)
(79)
51
(49)
(557)
(648)
(1,389)
(44)
(1,345)
(992)
(2,337)
$
2,269
637
6,368
(636)
(1)
278
8,915
5,562
(508)
40
1,325
257
6,676
756
483
1,032
—
48
8,995
193
(80)
33
(18)
(268)
47
(142)
(583)
(964)
(931)
25
(956)
65
(891)
(184)
(2,153) $
(117)
(774) $
(633)
(25)
10
888
—
(81)
159
130
(554)
6
228
(20)
(210)
160
(1,051)
196
(44)
26
(923)
(106)
96
(774)
4
189
4
93
26
316
(458)
69
(389)
(1,057)
(1,446)
(67)
(1,379)
3.11
$
2.46
26%
$
$
$
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:
(In millions except otherwise noted)
Retail
Texas
Year Ended December 31, 2017
Generation
East/West/
Other(a)
Subtotal
Corporate/
Eliminations
Total
Energy revenue
Capacity revenue
Retail revenue
Mark-to-market for economic hedging
activities
Contract amortization
Other revenue
Operating revenue
Cost of fuel
Other costs of sales(b)
Mark-to-market for economic hedging
activities
Contract and emission credit amortization
Gross margin
Less: Mark-to-market for economic hedging
activities, net
Less: Contract and emission credit
amortization, net
Economic gross margin
Business Metrics
MWh sold (thousands)
MWh generated (thousands)
$
— $
1,427
$
1,298
$
2,725
$
(1,089) $
—
6,374
(4)
(1)
—
6,369
(13)
(4,759)
181
—
22
—
94
—
35
1,578
(732)
(137)
(21)
(30)
596
—
(57)
—
200
2,037
(542)
(370)
13
(4)
618
—
37
—
235
3,615
(1,274)
(507)
(8)
(34)
(6)
4
219
—
(38)
(910)
1
1,120
(219)
—
1,636
612
6,378
252
(1)
197
9,074
(1,286)
(4,146)
(46)
(34)
$
$
1,778
$
658
$
1,134
$
1,792
$
(8) $
3,562
177
(1)
73
(30)
(44)
(4)
29
(34)
—
—
1,602
$
615
$
1,182
$
1,797
$
(8) $
206
(35)
3,391
42,662
38,694
27,923
21,338
(a) Includes International, Renewables, and Generation eliminations
(b) Includes purchased energy, capacity and emissions credits
66
(In millions except otherwise noted)
Retail
Texas
Year Ended December 31, 2016
Generation
East/West/
Other(a)
Subtotal
Corporate/
Eliminations
Total
Energy revenue
Capacity revenue
Retail revenue
Mark-to-market for economic hedging
activities
Contract amortization
Other revenue
Operating revenue
Cost of fuel
Other costs of sales(b)
Mark-to-market for economic hedging
activities
Contract and emission credit amortization
Gross margin
Less: Mark-to-market for economic hedging
activities, net
Less: Contract and emission credit
amortization, net
Economic gross margin
Business Metrics
MWh sold (thousands)
MWh generated (thousands)
$
— $
1,705
$
1,538
$
3,243
$
(974) $
—
6,332
(1)
(1)
—
6,330
(8)
(4,675)
365
(6)
18
—
(543)
—
48
1,228
(704)
(147)
67
(29)
624
—
(22)
—
265
2,405
(566)
(463)
6
(5)
642
—
(565)
—
313
3,633
(1,270)
(610)
73
(34)
$
$
2,006
$
415
$
1,377
$
1,792
$
364
(7)
(476)
(29)
(16)
(5)
(492)
(34)
1,649
$
920
$
1,398
$
2,318
$
(5)
36
(70)
—
(35)
(1,048)
—
1,001
70
—
23
—
—
23
$
$
2,269
637
6,368
(636)
(1)
278
8,915
(1,278)
(4,284)
508
(40)
3,821
(128)
(41)
3,990
42,108
37,676
32,625
23,748
(a) Includes International, Renewables, and Generation eliminations
(b) Includes purchased energy, capacity and emissions credits
The table below represents the weather metrics for 2017 and 2016:
Years ended
December 31,
Quarter ended
December 31,
Quarter ended
September 30,
Quarter ended
June 30,
Quarter ended
March 31,
Weather Metrics
Texas
East/West
Texas
East/West
Texas
East/West
Texas
East/West
Texas
East/West
2017
CDDs(a)
HDDs(a)
2016
CDDs
HDDs
10 year average
CDDs
HDDs
3,068
1,270
3,030
1,422
2,897
1,928
1,155
3,198
1,169
3,190
1,043
3,504
311
665
382
498
266
691
84
1,157
71
1,145
67
1,227
1,568
1
1,675
—
1,650
5
770
33
806
23
705
40
966
32
892
47
989
64
281
380
273
410
254
438
223
572
82
878
88
1,025
20
1,628
19
1,612
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
67
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
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) - Texas
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)
$
$
$
Years ended December 31,
2017
2016
$
$
$
6,104
187
83
(4)
(1)
6,369
(4,772)
181
—
1,778
177
(1)
1,602
36,169
6,221
20,400
3,212
2,862
2,876
6,096
154
82
(1)
(1)
6,330
(4,683)
365
(6)
2,006
364
(7)
1,649
35,102
6,764
18,906
2,166
2,778
2,818
(a)
(b)
Includes intercompany sales of $5 million and $4 million in 2017 and 2016, respectively, representing sales from Retail to the Texas region
Includes intercompany purchases of $1,090 million and $993 million in 2017 and 2016, respectively
Retail gross margin decreased $227 million and retail economic gross margin decreased $47 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 cost of $28 million or approximately
$0.50 per MWh driven by a decrease in supply costs
$
(75)
(In millions)
Lower gross margin related to the impact of Hurricane Harvey in 2017, driven by a reduction in load of
200,000 MWh resulting in an impact of $9 million and the unfavorable impact of selling back excess supply
along with $7 million of customer relief
Lower gross margin due to milder weather conditions in 2017 as compared to 2016 resulting in a reduction in
load of 350,000 MWh
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
(16)
(11)
55
(47)
(186)
6
(227)
$
$
68
Generation gross margin and economic gross margin
Generation gross margin was flat and generation economic gross margin decreased $521 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 change in generation gross margin and generation economic gross margin:
Texas Region
Lower gross margin due to a 14% decrease in average realized prices due to lower hedged power prices
Lower gross margin due to lower gas generation driven by the current mothball status of Gregory in Texas
Higher gross margin due to a 17% increase in coal generation driven by the timing of planned and unplanned
outages
Higher gross margin due to a decrease in tolling prices in 2017 offset by the cancellation of the Greens Bayou
RMR agreement in 2017
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 partially offset by increased generation at Cottonwood
Lower gross margin due to a lower cost of market adjustment for fuel oil inventory
Lower gross margin due to lower load contracted prices coupled with slightly lower volumes
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
Lower gross margin due to lower capacity bi-lateral margins in 2017
Lower gross margins due to the sale of certain renewable assets in 2017
Lower gross margin at Agua driven by lower sales volumes resulting from weather and outages in 2017
Lower gross margins due to higher business interruption proceeds from Cottonwood in 2016 offset by Ivanpah
proceeds in 2017
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
Increase in contract and emission credit amortization
Decrease in gross margin
(In millions)
$
(352)
(17)
55
5
4
(305)
549
(1)
243
$
$
(In millions)
$
(63)
(43)
(33)
(28)
(20)
(11)
(10)
(5)
(4)
1
(216)
(28)
1
(243)
$
$
69
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 $334 million in 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 are as follows:
Year Ended December 31, 2017
Generation
Retail
Texas
East/West/
Other
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)/gains 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 gains/(losses) on open positions related to
economic hedges
Total mark-to-market gains/(losses) in operating costs and
expenses
$
$
$
$
(2) $
140
$
(72) $
64
$
(2)
(4) $
(46)
15
94
$
(57) $
155
219
$
130
122
252
(1) $
(17) $
(1) $
(64) $
(83)
182
(4)
14
(155)
37
181
$
(21) $
13
$
(219) $
(46)
(a) Represents the elimination of the intercompany activity between Retail and Generation
The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows:
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 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
$
365
$
(a) Represents the elimination of the intercompany activity between Retail and Generation
Year Ended December 31, 2016
Generation
Retail
Texas
East/West/
Other
Elimination (a)
Total
(In millions)
(3) $
(390) $
(87) $
33
$
(447)
2
(153)
65
(103)
(1) $
(543) $
(22) $
(70) $
305
$
—
60
27
—
40
67
$
$
20
$
(33) $
(12)
(2)
—
103
6
$
70
$
(189)
(636)
319
(12)
201
508
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.
70
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 $252 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, as well as
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 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
Operations and Maintenance Expense
Year Ended December 31,
2017
2016
(In millions)
$
$
43
(11)
32
$
$
71
28
99
Generation
Retail
Texas
East/West/
Other
Corporate Eliminations
Total
Year Ended December 31, 2017
Year Ended December 31, 2016
$
$
224
247
$
$
387
434
$
$
(In millions)
458
605
$
$
31
43
$
$
(3) $
(4) $
1,097
1,325
Operations and maintenance expenses decreased by $228 million for the year ended December 31, 2017, compared to
the same period in 2016, due to the following:
Decrease in operation and maintenance expenses due to major maintenance activities and environmental
control work in the East offset by higher variable operating costs
Decrease in operations and maintenance expenses due to timing of planned outages in Texas
Decrease in Retail operations and maintenance expenses due to reduced headcount
Decrease in operations and maintenance expenses due to the gain on sale of Jewett Mine dragline in 2017
Decrease in operations and maintenance expense due to reductions at Residential Solar
Decrease in operations and maintenance expenses due to gain on sale of fixed assets in the East
Decrease in operation and maintenance expenses due to a reduction in headcount related to the sale of the
engine services business
Decrease in operations and maintenance expenses due to the sale of wind assets in 2016 and early 2017
Other
Other cost of operations
(In millions)
$
$
(100)
(32)
(22)
(18)
(16)
(15)
(10)
(10)
(5)
(228)
Retail
Texas
Generation
East/West/
Other
Corporate
Total
Year Ended December 31, 2017
Year Ended December 31, 2016
$
$
99
93
$
$
81
75
$
$
(In millions)
97
88
$
$
— $
1
$
277
257
Other cost of operations, comprised of asset retirement expense, insurance expense and property tax expense, increased
by $20 million for the year ended December 31, 2017, compared to the same period in 2016.
71
Depreciation and Amortization
Year Ended December 31, 2017
Year Ended December 31, 2016
Retail
Generation
Corporate
Total
$
$
110
114
$
$
(In millions)
454
$
593
$
32
49
$
$
596
756
Depreciation and amortization expense decreased by $160 million for the year ended December 31, 2017, compared to the
same period in 2016, primarily due to due to the Jewett Mine being fully depreciated in December 2016 as well as impairments
in 2016.
Impairment Losses
In 2017, the Company recorded impairment losses of $1,534 million related to various facilities, as well as goodwill for its
Texas reporting unit, as further described in Item 15 — Note 9, Asset Impairments and Note 10, Goodwill and Other Intangibles,
to the Consolidated Financial Statements.
In 2016, the Company recorded impairment losses of $483 million related to various facilities, as well as goodwill for its
Texas and Home Solar reporting units, as further described in Item 15 - Note 9, Asset Impairments to the Consolidated Financial
Statements.
Selling, General and Administrative Expenses
Year Ended December 31, 2017
Year Ended December 31, 2016
Retail
Generation
Corporate
Total
$
$
452
498
$
$
(In millions)
215
279
$
$
169
255
$
$
836
1,032
Selling, general and administrative expenses decreased by $196 million(a) for the year ended December 31, 2017
compared to the same period in 2016, primarily due to a reduction in personnel costs and selling and marketing activities as the
Company continues to focus on cost management.
(a) Approximately $98 million of additional cost savings were achieved in the year ended December 31, 2017, as compared to the year ended December 31,
2016, as the savings became permanent through the Transformation Plan
Development Costs
Development costs decreased by $26 million for the year ended December 31, 2017, compared to the same period in 2016,
due to the strategic decision for a more focused development program primarily related to Renewables and the sale of EVgo in
2016.
Gain/(Loss) on Sale of Assets
Gain on sale of assets for the year ended December 31, 2017, represents a gain on the sale of land. The loss on sale of
assets for the year ended December 31, 2016 is primarily due to the loss on sale of the Company's majority interest in its EVgo
business to Vision Ridge Partners, which resulted in a loss on sale as described in Item 15 — Note 3, Acquisitions, Discontinued
Operations and Dispositions, to the Consolidated Financial Statements.
Impairment Losses on Investments
For the year ended December 31, 2017, the Company recorded impairment losses of $79 million, which is primarily due to
impairments on the Company's interests in Petra Nova Parish Holdings as well as as impairments on other investments as further
described in Item 15 — Note 9, Asset Impairments, to the Consolidated Financial Statements.
For the year ended December 31, 2016, the Company recorded impairment losses on certain of its cost and equity method
investments of $270 million, as further described in Item 15 — Note 9, Asset Impairments, to the Consolidated Financial Statements.
72
Loss on Debt Extinguishment
A loss on debt extinguishment of $49 million was recorded for the year ended December 31, 2017, primarily driven by the
repurchase of 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.
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.
Interest Expense
NRG's interest expense decreased by $26 million for the year ended December 31, 2017, compared to the same period
in 2016, primarily due to lower debt balances resulting in less interest.
Income Tax Expense
For the year ended December 31, 2017, NRG recorded an income tax benefit of $44 million on a pre-tax loss of $1,389
million. For the same period in 2016, NRG recorded an income tax expense of $25 million on pre-tax loss of $931 million. The
effective tax rate was 3.2% and (2.7)% 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 federal statutory tax 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 PTCs 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.
Loss from continuing operations before income taxes
Tax at federal statutory tax rate
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
Impact of changes is in effective state
AMT refundable credit
Other
Income tax (benefit)/expense
Effective income tax rate
Year Ended December 31,
2017
2016
(In millions
except as otherwise stated)
$
$
$
$
(1,389)
(486)
19
2
665
(660)
455
(5)
30
—
(8)
(5)
—
(64)
13
(44)
3.2%
(931)
(326)
—
10
—
—
382
22
—
1
(7)
2
(59)
—
—
25
(2.7)%
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.
73
(Loss)/Income from Discontinued Operations, Net of Income Tax
(In millions)
South Central
Yield Renewables Platform & Carlsbad
Genon
(Loss)/income from discontinued operations, net of tax
Year Ended December 31,
2017
2016
Change
$
$
$
87
(290)
(789)
(992) $
72
(99)
92
65
$
$
15
(191)
(881)
(1,057)
For the year ended December 31, 2017, NRG recorded a loss from discontinued operations, net of income tax of $992
million, an increase of $1.1 billion in losses from discontinued operations, net of income tax for the same period in 2016, as further
described in Item 15 — Note 3 Acquisitions, Discontinued Operations and Dispositions.
(Loss)/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 of $992
million, of which $359 million was related to operations of GenOn, Carlsbad, NRG Yield Inc. and its Renewables Platform,
and the South Central Portfolio and $633 million was related to the loss, fees and other expenses associated with the
dispositions.
For the year ended December 31, 2016, NRG recorded income from discontinued operations, net of income tax of $65 million
which was related to operations of GenOn, NRG Yield Inc. and its Renewables Platform, and the South Central Portfolio.
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.
74
Liquidity and Capital Resources
Liquidity Position
As of December 31, 2018 and 2017, NRG's liquidity, excluding collateral funds deposited by counterparties, was
approximately $2.0 billion and $2.8 billion, respectively, comprised of the following:
As of December 31,
2018
2017
Cash and cash equivalents:
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
$
$
$
(In millions)
563
6
11
580
1,397
1,977
$
770
85
194
1,049
1,711
2,760
For the year ended December 31, 2018, total liquidity, excluding collateral funds deposited by counterparties, decreased by
$783 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, 2018 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.
Credit Ratings
On December 6, 2018, Moody's upgraded the NRG corporate family rating to Ba2 and senior unsecured rating to Ba3 with
positive outlook. The rating agency also affirmed the company's senior secured rating at Baa3.
On September 10, 2018, S&P upgraded its issuer credit rating to BB with a stable outlook. At the same time they raised the
issue-level secured and unsecured ratings to BBB and BB respectively.
The following table summarizes the Company's current credit ratings:
NRG Energy, Inc.
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
S&P
BB Stable
BB
BB
BB
BB
BBB-
Moody's
Ba2 Positive
Ba3
Ba3
Ba3
Ba3
Baa3
75
Sources of Liquidity
The principal sources of liquidity for NRG's operating and capital expenditures are expected to be derived from cash on
hand, cash flows from operations, cash proceeds from future sales of assets and financing arrangements. As described in
Item 15 — Note 11, Debt and Capital Leases, to the Consolidated Financial Statements, the Company's financing arrangements
consist mainly of the Senior Credit Facility, the Senior Notes, and project-related financings.
Asset Sale Proceeds
The table below represents the approximate purchase price received from sale transactions and related financings
completed by the Company during the year ended December 31, 2018.
Sales
NRG Yield, Inc and Renewables Platform
Buckthorn Solar (a)
UPMC Thermal Project (a)
BETM
Canal 3(b)
Other Sales
Completed sales transactions as of December 31, 2018
(a) Sale of assets to NRG Yield, Inc., prior to discontinued operations
Cash Proceeds
(in millions)
1,348
42
84
70
167
12
1,723
$
$
(b) In addition to cash proceeds from sale, amount includes $151 million related to a financing arrangement prior to the sale
The table below represents the cash proceeds received from sales transactions, excluding working capital or other adjustments,
completed by the Company by February 28, 2019.
Expected Sales
South Central Portfolio
Carlsbad
Cash proceeds from sales transactions in 2019
2048 Convertible Senior Notes Issuance
Close Date
February 4, 2019
February 27, 2019
$
$
Cash Proceeds
(in millions)
1,000
387
1,387
On May 24, 2018, the Company issued $575 million in aggregate principal amount at par of 2.75% convertible senior notes
due 2048.
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 EME (including Midwest Generation) acquisitions 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, 2018, all hedges under the first liens were out-of-the-money on a counterparty aggregate basis.
76
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, 2018:
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
831
18%
712
16%
596
13%
2021
2020
2019
2022
743
16%
acquired in the Midwest Generation acquisition and NRG's assets that have project-level financing
Uses of Liquidity
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 11, Debt
and Capital Leases, to the Consolidated Financial Statements; (iii) capital expenditures, including repowering 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 14, Capital Structure, to the Consolidated Financial Statements.
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 (e.g. buying fuel before receiving
energy revenues); (iv) initial collateral for large structured transactions; and (v) collateral for project development. As of December 31,
2018, commercial operations had total cash collateral outstanding of $287 million and $793 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, 2018, total
collateral held from counterparties was $33 million in cash and $108 million of letters of credit.
Future liquidity requirements may change based on the Company's hedging activities and structures, power purchases and sales,
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.
2023 Term Loan Facility
In accordance with the terms of the Credit Agreement, on October 5, 2018, the Company initiated an asset sale offer to purchase
a portion of its Term Loan following the sale of NRG Yield and the Renewables Platform. The offer expired on November 5, 2018,
and $260 million of Term Loan holders accepted the offer. As a result, the Company prepaid $155 million of Term Loans as part of its
de-leveraging plan, as well as established an incremental first lien secured loan term facility under the Senior Credit Facility in the
aggregate principal amount of $105 million on the same terms and conditions to stay within its debt reduction target.
In accordance with the terms of the credit agreement, upon the consummation of the sales of the South Central Portfolio and
Carlsbad, the Company will initiate asset sale offers to purchase a portion of its Term Loan. The Company has one year from the date
of each sale to initiate the offer.
Senior Note Repurchases in 2018
During the year ended December 31, 2018, the Company redeemed $1.1 billion in aggregate principal of its Senior Notes for
$1.1 billion, which included accrued interest of $14 million. In connection with the redemptions, a $38 million loss on debt
extinguishment was recorded in 2018, which included the write-off of previously deferred financing costs of $7 million.
77
In millions, except percentages
5.750% senior notes due 2028
6.250% senior notes due 2022
Total at June 30, 2018
6.250% senior notes due 2022
5.750% senior notes due 2028
6.625% senior notes due 2027
Total at September 30, 2018
6.250% senior notes due 2022
Total at December 31, 2018
(a) Includes accrued interest of $14 million
Senior Note Redemptions in 2017
Principal
Repurchased
Cash Paid (a)
Average Early Redemption
Percentage
$
$
$
$
29
14
43
493
20
20
576
485
1,061
$
$
$
$
30
15
45
512
20
21
598
508
1,106
99.24%
103.25%
103.13%
99.13%
103.06%
103.13%
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 percentages
7.625% senior notes due 2018
7.875% senior notes due 2021
6.625% senior notes due 2023
Total
(a) Includes accrued interest of $29 million
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%
78
Debt Service Obligations
Principal payments on debt and capital leases as of December 31, 2018 are due in the following periods:
Description
Recourse Debt:
Senior notes, due 2024
Senior notes, due 2026
Senior notes, due 2027
Senior notes, due 2028
Convertible Senior Notes, due 2048
Term loan facility, due 2023
Tax-exempt bonds
Subtotal Recourse Debt
Non-Recourse Debt:
Agua Caliente Borrower 1, due 2038
Midwest Generation, due 2019
Other
Subtotal Non-Recourse Debt
Subtotal long-term debt
Capital Leases:
Capital leases
Subtotal Capital Leases
Total Debt and Capital Leases
2019
2020
2021
2022
(In millions)
2023
Thereafter
Total
$
— $
— $
— $
— $ — $
733
$
733
—
—
—
—
17
—
17
3
48
6
57
74
—
—
74
$
—
—
—
—
18
—
18
3
—
5
8
26
—
—
26
$
—
—
—
—
17
—
17
3
—
6
9
26
1
1
27
$
—
—
—
—
17
—
17
3
—
5
8
25
—
—
25
—
—
—
—
1,629
—
1,629
2
—
4
6
1,000
1,230
821
575
—
466
4,825
72
—
8
80
1,635
4,905
1,000
1,230
821
575
1,698
466
6,523
86
48
34
168
6,691
—
—
$ 1,635
$
—
—
4,905
1
1
$ 6,692
$
In addition to the debt and capital leases shown in the above table, NRG had issued $1.0 billion of letters of credit under the
Company's $2.4 billion Revolving Credit Facility as of December 31, 2018.
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, 2018, and the estimated capital expenditure and growth investments forecast
for 2019.
Maintenance
Environmental
Growth
Investments
Total
Retail
Generation
Texas
East/West/Other (a)
Corporate
Total cash capital expenditures for the year ended
December 31, 2018
Funding from debt financing, net of fees
XOOM acquisition and integration
Other investments(b)
Total capital expenditures and investments, net of financings
Estimated capital expenditures for 2019
(a) Includes International, Renewables and Cottonwood
(b) Other investments include restricted cash activity and acquisitions
$
$
$
19
$
(In millions)
— $
71
$
77
54
9
159
—
—
—
159
155
$
$
—
1
—
1
—
—
—
1
3
$
$
—
135
22
228
(118)
208
176
494
65
$
$
90
77
190
31
388
(118)
208
176
654
223
• Growth Investments capital expenditures — For the year ended December 31, 2018, the Company's growth investment
capital expenditures included $134 million for repowering Canal 3, and $94 million for the Company's other growth
projects.
79
Environmental Capital Expenditures Estimate
NRG estimates that environmental capital expenditures from 2019 through 2023 required to comply with environmental
laws will be approximately $35 million. These costs are primarily associated with the cost of adding NOx controls in Connecticut.
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.
SO2
NOx
Mercury
Particulate
Units
State
Control
Equipment
Install
Date
Control
Equipment
LNBOFA/
SCR
Install
Date
Control
Equipment
Install
Date
Control
Equipment
Install Date
1999/2011
ACI/CDS/FF
2008/2011
ESP/FF
1980/2011
CDS
Gas
Conversion
2011
2016
OFA
2016
Gas
Conversion
Indian River 4
Joliet 6, 7, 8
Limestone 1-2
Powerton 5
Powerton 6
W.A. Parish 5, 6, 7
W.A. Parish 8
Waukegan 7
Waukegan 8
Will County 4
DE
IL
TX
IL
IL
TX
TX
IL
IL
IL
FGD
DSI
DSI
FF co-
benefit
FGD
DSI
DSI
DSI
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
2016
2015
2009
2009
2015
2015
Gas
Conversion
2016
ESP
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
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
SCR - Selective Catalytic Reduction
SNCR - Selective Non-Catalytic Reduction
The following table summarizes the estimated environmental capital expenditures for the referenced periods by region:
2019
2020
2021
2022
2023
Total
Texas
East/West
Total
(In millions)
2
5
8
4
—
19
$
$
1
8
3
4
—
16
$
$
$
$
3
13
11
8
—
35
Common Stock Dividends
The Company returned $37 million of capital to shareholders in the year ended 2018 through a $0.12 dividend per common
share.
On January 23, 2019, 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, 2019, to stockholders of record as of February 1, 2019. The Company's
common stock dividends are subject to available capital, market conditions, and compliance with associated laws and regulations.
80
Share Repurchases
In 2018, the Company's board of directors authorized the Company to repurchase $1.5 billion of its common stock.
During the year ended December 31, 2018, the Company repurchased a total of 35,234,664 shares under these programs for
$1.25 billion, and the remaining $250 million was repurchased by February 28, 2019. The average price paid per share for the
$1.5 billion share repurchase was $36.24. In addition, the Company's board of directors authorized in February 2019 an
additional $1 billion share repurchase program to be executed in 2019. See Note 14, Capital Structure, for additional
discussion.
Targeted Debt Reduction
NRG is revising its balance sheet target ratios in order to further strengthen its balance sheet. In order to achieve the revised
balance sheet targets, the Company is reserving up to $600 million in 2019 capital which may be allocated toward debt reduction.
Small Book Acquisitions
During 2018, the Company has acquired several books of customers totaling approximately 115,000 customers, along with
brand names, for $44 million.
Petra Nova Debt Repayment
NRG has guaranteed up to $124 million of Petra Nova's $248 million project debt to its lenders for purposes of debt repayment
in the event Petra Nova is unable to meet its projected debt coverage covenant as stipulated in its financing agreements. The
covenant test and possible repayment, or a portion thereof, are scheduled to occur in the third quarter of 2019. Once such payment
is made, NRG's guarantee will terminate.
81
Cash Flow Discussion
2018 compared to 2017
The following table reflects the changes in cash flows for the comparative years:
(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,
2018
2017
Change
$
$
1,377
(205)
(1,526)
$
1,610
(639)
(1,138)
(233)
434
(388)
Changes to net cash provided by operating activities were driven by:
Change in cash from discontinued operations
Decrease in inventory during 2017 as a result of initiatives related to the Transformation Plan to reduce
inventory levels
GenOn settlement payment in July 2018, net of insurance proceeds received in December 2018
Changes in cash collateral in support of risk management activities due to changes in commodity prices
Increase in operating income adjusted for non-cash items
Increase in working capital in 2018 as a result of initiatives related to the Transformation Plan to increase
working capital
Net Cash Used By Investing Activities
Changes to net cash used by investing activities were driven by:
Increase in proceeds from sale of assets and sale of discontinued operations
Change in cash from discontinued operations
Decrease in net investments in unconsolidated affiliates
Cash removed due to deconsolidation of Agua Caliente and Ivanpah in 2018
Increase in cash paid for acquisitions in 2018, primarily for the XOOM acquisition
Decrease in net distributions received from discontinued operations
Increase in capital expenditures for growth investments and maintenance in generation assets
Increase in investments in nuclear decommissioning trust net of proceeds from sales
Decrease in sales of emissions, net of purchases
Decrease in insurance proceeds received in 2018
Decrease in cash grants received in 2018
Other
(In millions)
$
(380)
(112)
(63)
(25)
323
24
(233)
$
(In millions)
1,134
$
254
18
(268)
(229)
(210)
(134)
(48)
(47)
(22)
(8)
(6)
434
$
82
Net Cash Used By Financing Activities
Changes in net cash used by financing activities were driven by:
Repurchases of common stock in 2018, from open market repurchases and the ASR agreement
Decrease in proceeds from issuance of long-term debt
Change in cash from discontinued operations
Decrease in payments for short and long-term debt
Decrease in notes issued to affiliates
Increase in cash received from issuance of stock due to exercise of employee share-based compensation
Decrease in net distributions paid to noncontrolling interests from subsidiaries
Other
(In millions)
$
(1,250)
(68)
640
150
99
21
14
6
(388)
$
2017 compared to 2016
The following table reflects the changes in cash flows for the comparative years:
(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
$
$
1,610
(639)
(1,138)
$
1,908
(757)
(768)
(298)
118
(370)
Changes to net cash provided by operating activities were driven by:
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
Decrease in inventory as a result of initiatives related to the Transformation Plan to reduce inventory levels in
2017 as compared to 2016
Change in cash from discontinued operations
(In millions)
$
(476)
(121)
(67)
83
283
(298)
$
83
Net Cash Used By Investing Activities
Changes to net cash used by investing activities were driven by:
Decrease in capital expenditures in 2017
Increase in proceeds from sale of assets
Increase due to net distributions received from discontinued operations
Increase in sales of emissions, net of purchases
Increase in investments in nuclear decommissioning trust net of proceeds from sales
Change in cash from discontinued operations, primarily due to increased capital expenditures in 2017 and asset
sales in 2016
Decrease in cash grants received in 2017
Increase due to net contributions to unconsolidated affiliates
Other
Net Cash Used By Financing Activities
Changes in net cash used by financing activities were driven by:
Decrease in payments for short and long-term debt primarily due to repurchases of Senior Notes in 2016
Change due to repurchase of preferred stock in 2016
Decrease in debt extinguishment costs
Decrease in deferred debt issuance costs
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
Decrease in borrowings primarily related to Agua Caliente borrowings in 2016
Change in cash from discontinued operations
Decrease due to payment notes issued to affiliates in 2017
Other
(In millions)
290
$
189
208
67
30
(591)
(28)
(24)
(23)
118
$
(In millions)
3,262
$
226
79
43
38
(3,234)
(652)
(125)
(7)
(370)
$
84
NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740
As of December 31, 2018, the Company had domestic pre-tax book income of $468 million and a foreign pre-tax book loss
of $1 million. For the year ended December 31, 2018, the Company generated an NOL of $8.0 billion due to a current year taxable
loss. As of December 31, 2018, the Company has cumulative domestic federal NOL carryforwards of $10.7 billion, which will
begin expiring in 2031 and cumulative state NOL carryforwards of $5.6 billion. NRG also has cumulative foreign NOL
carryforwards of $213 million, which do not have an expiration date. In addition to the above NOLs, NRG has a $442 million
indefinite carryforward for interest deductions, as well as $381 million of tax credits to be utilized in future years. As a result of
the Company's tax position, including the benefit of $9.6 billion of tax losses and worthless stock deduction upon GenOn emerging
from bankruptcy, and based on current forecasts, the Company anticipates income tax payments, primarily due to state and local
jurisdictions, of up to $20 million in 2019.
The Company has recorded short-term and long-term receivables of $35 million and $34 million, respectively, representing
refundable AMT credits from the IRS, 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. Of this amount, short-term and long-
term payables of $11 million each are due to GenOn for their share of minimum tax credits.
In addition to these amounts, the Company has $26 million of tax effected uncertain state tax benefits for which the Company
has recorded a non-current tax liability of $30 million (including accrued interest) until such final resolution with the related taxing
authority.
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 25 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, 2018, 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. One
of these investments is considered a variable interest entity for which NRG is not the primary beneficiary.
NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $992 million as of
December 31, 2018. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG.
See also Item 15 — Note 15, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Consolidated
Financial Statements for additional discussion.
85
Contractual Obligations and Commercial Commitments
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 11, Debt and Capital Leases, Note 21, Commitments and
Contingencies, and Note 25, Guarantees, to the Consolidated Financial Statements for additional discussion.
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,
2018
Under
1 Year
1-3 Years
3-5 Years
Over
5 Years
Total (a)
2017 Total
(In millions)
$
464
$
807
$
2,349
$
6,520
$ 10,140
$ 13,895
—
61
227
30
39
7
32
1
102
278
25
53
13
62
—
91
129
12
82
12
43
—
317
209
1
79
25
144
1
571
843
68
253
57
281
5
675
1,335
68
205
74
296
$
860
$
1,341
$
2,718
$
7,295
$ 12,214
$ 16,553
(a) Excludes $26 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 $679 million of asset retirement obligations which are discussed in Item 15 — Note 12 , 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)
By Remaining Maturity at December 31,
2018
Guarantees
Under
1 Year
1-3 Years
3-5 Years
Over
5 Years
Total
2017 Total
Letters of credit and surety bonds(a)(b)
Asset sales guarantee obligations
Other guarantees
Total guarantees
$
$
1,138
—
—
1,138
$
$
79
4
105
188
$
$
(In millions)
— $
257
—
257
$
36
532
616
1,184
$
$
1,253
793
721
2,767
$
$
1,003
312
645
1,960
(a) As of December 31, 2017 excludes $92 million of letters of credit issued under the intercompany revolving credit agreement between NRG and GenOn
(b) December 31, 2018 includes $32 million of letter of credit and surety bonds for the benefit of GenOn where NRG holds cash or letter of credit to back stop
the liability
86
Fair Value of Derivative Instruments
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 debt, NRG enters into interest rate swap agreements.
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, 2018, based on their level within
the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at December 31, 2018. 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 Gains/(Losses)
Fair value of contracts as of December 31, 2017
Contracts realized or otherwise settled during the period
Contracts acquired during the period
Changes in fair value
Fair value of contracts as of December 31, 2018
(In millions)
103
$
(99)
11
89
104
$
Fair Value of Contracts as of December 31, 2018
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
$
$
(58) $
106
43
91
$
(25) $
79
(1)
53
$
(4) $
(1)
(4)
(9) $
— $
(13)
(18)
(31) $
(87)
171
20
104
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, 2018, NRG's net derivative asset was $104 million, an increase to total fair value of $1 million as
compared to December 31, 2017. This increase was primarily driven by gains in fair value and contracts acquired during the
period, largely offset by roll off trades that were settled during the period.
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 a decrease of approximately $230 million in the net value of derivatives
as of December 31, 2018.
The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of the derivative contracts would result
in an increase of approximately $221 million in the net value of derivatives as of December 31, 2018.
87
Critical Accounting Policies and Estimates
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
88
Derivative Instruments
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 borrowings for interest rate
swaps occurring within a specified time period. 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 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, 2018, NRG had a valuation allowance of $3.8 billion. This amount is comprised of domestic federal
net deferred tax assets of approximately $3.3 billion, domestic state net deferred tax assets of $454 million, foreign net operating
loss carryforwards of $62 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.
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.
Evaluation of Assets for Impairment and Other-Than-Temporary Decline in Value
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
89
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 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 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 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 its operations and
the physical and economic characteristics of each of its businesses. During the fourth quarter of 2018, 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. There were no significant changes to the Company's long-term view of natural gas prices
despite management's expectation of continued trends towards more renewables and energy storage. There were minimal changes
to the long-term view of energy and capacity prices, which did not have a significant negative impact on the Company's coal,
nuclear, and renewable facilities.
The following long-lived asset impairment was recorded during 2018, as further described in Item 15 —Note 9, Asset
Impairments, to the consolidated financial statements:
Guam— During the fourth quarter of 2018, the Company concluded its wholly-owned subsidiary, NRG Solar Guam, LLC,
was held for sale after 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, 2018 based on the contractual sale price, which resulted in an
impairment loss of $12 million. The sale was completed on February 20, 2019.
Keystone and Conemaugh — On June 29, 2018, the Company entered into an agreement to sell its approximately 3.7%
interests in the Keystone and Conemaugh generating stations. The Company recorded impairment losses of $14 million for
Keystone and $14 million for Conemaugh to adjust the carrying amount of the assets to fair value based on the contractual sale
price. The transaction closed on September 5, 2018.
Dunkirk — During the second quarter of 2018, NRG ceased its development of the project to add gas capability at the Dunkirk
generating station. The project was put on hold in 2015 pending the resolution of a lawsuit filed by Entergy Corporation against
the NYPSC, which challenged the legality of its contract with Dunkirk. The lawsuit was later dropped and development continued,
but the delay imposed a new requirement on Dunkirk to enter into the NYISO interconnection study process. The NYISO studies
have concluded that extensive electric system upgrades would be necessary for the station to return to service. This would cause
the Company to incur a material increase in cost and delay the project schedule that would render the project impractical.
Consequently, the Company has recorded an impairment loss of $46 million, reducing the carrying amount of the related assets
to $0.
Other Impairments — As of December 31, 2018, the Company recorded additional impairment losses of approximately $13
million. 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 the date of sale or in connection with an impairment indicator.
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Equity and Cost Method Investments — 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,
2018, the Company recorded impairment losses on its equity method investments of $15 million due to declines in value.
Goodwill and Other Intangible Assets
At December 31, 2018, NRG reported goodwill of $573 million, consisting of $165 million associated with the acquisition
of Midwest Generation and $408 million for retail business acquisitions. The balance of goodwill increased by $34 million in
2018 due to the acquisition of XOOM.
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 is tested for impairment 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 an 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 and Commodity Retail reporting units. The Company determined
it was more likely than not that the fair value of the goodwill attributed to these reporting units were more than their carrying
amount and accordingly, no impairment existed for the year ended December 31, 2018.
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, 2018:
Reporting Unit
Midwest Generation (Generation Segment)
Texas Non-Commodity (Retail Segment)
% Fair Value Over
Carrying Value
132%
135%
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 forecasts 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, driven by 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;
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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 forecasts 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 budget for the Texas Non-Commodity
reporting unit. 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.
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 21, Commitments and Contingencies, to the consolidated financial statements.
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.
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Item 7A — Quantitative and Qualitative Disclosures About Market 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 retail businesses, 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, 2018, the VaR for NRG's commodity portfolio, including generation assets, load obligations and bilateral
physical and financial transactions calculated using the VaR model was $44 million.
The following table summarizes average, maximum and minimum VaR for NRG for the years ended December 31, 2018
and 2017:
(In millions)
VaR as of December 31,
For the year ended December 31,
Average
Maximum
Minimum
$
$
2018
2017
$
$
44
59
75
44
46
51
66
40
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 $14 million
as of December 31, 2018, primarily driven by asset-backed transactions.
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Interest Rate Risk
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 11, 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, 2018, the counterparties would have owed the Company
$37 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, 2018, a 1% change in interest rates would result in a $7 million change in interest
expense on a rolling twelve month basis.
As of December 31, 2018, the Company's debt fair value was $6.7 billion and carrying value was $6.6 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 $510 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 $125
million as of December 31, 2018, 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 $62 million as of December 31, 2018. This analysis uses simplified assumptions and
is calculated based on portfolio composition and margin-related contract provisions as of December 31, 2018.
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, 2018, aggregate counterparty credit exposure to a significant portion of the Company's counterparties
totaled $301 million, of which the Company held collateral (cash and letters of credit) against those positions of $123 million
resulting in a net exposure of $180 million. Approximately 66% of the Company's exposure before collateral is expected to roll
off by the end of 2020. 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, 2018, 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)
11%
89
100%
Net Exposure (a) (b)
(% of Total)
49%
51
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 currently has no exposure to any individual wholesale counterparty in excess of 10% of the total net exposure
discussed above as of December 31, 2018. 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.
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.
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Long Term Contracts
Counterparty credit exposure described above excludes credit risk exposure under certain long term contracts, including
California tolling agreements 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, 2018, aggregate credit risk exposure managed by NRG to these counterparties was
approximately $434 million for the next five years. This amount excludes potential credit exposures for projects with long-term
PPAs that have not reached commercial operations and any exposure for entities classified as a discontinued operation.
NRG through its unconsolidated affiliates Ivanpah and Agua Caliente has exposure to PG&E of approximately $321 million
for the next five years. As a result of the bankruptcy filing by PG&E on January 29, 2019, it is uncertain whether and to what
extent the bankruptcy may have on these contracts. For further discussion see Note 15 Investments Accounted for by the Equity
Method and Variable Interest Entities.
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, 2018, 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 $85 million, $68 million, and $45
million for the years ending December 31, 2018, 2017, and 2016, 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,
2018 was $16 million. The collateral required for contracts with credit rating contingent features that are in a net liability position
as of December 31, 2018 was $14 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 $11 million as of December 31,
2018.
Currency Exchange 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
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, 2018.
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 2018 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, 2018.
On June 1, 2018, we acquired XOOM Energy, LLC, as further described in Note 3, Acquisitions, Discontinued Operations
and Dispositions. XOOM Energy, LLC's assets comprised approximately 2.1% of the Company's total assets as of December 31,
2018 and approximately 2.3% of the Company's total revenues for the year ended December 31, 2018. As of December 31, 2018,
we are in the process of evaluating the internal controls of the acquired business and integrating it into our existing operations.
97
The acquired business has, therefore, been excluded from management's assessment of internal control over financial reporting
for the year ended December 31, 2018.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2018 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.
98
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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,
2018, 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, 2018, 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, 2018 and 2017, the related consolidated statements
of operations, comprehensive income/(loss), stockholders’ equity, and cash flows for each of the years in the three-year period
ended December 31, 2018, and the related notes and financial statement schedule II (collectively, the consolidated financial
statements), and our report dated February 28, 2019 expressed an unqualified opinion on those consolidated financial statements.
Management excluded XOOM Energy, LLC (XOOM), acquired by the Company during 2018, from their assessment of the
effectiveness of the Company's internal control over financial reporting as of December 31, 2018. XOOM's assets comprised
approximately 2.1% of the Company's total assets as of December 31, 2018 and approximately 2.3% of the Company's total
revenues for the year ended December 31, 2018. Our audit of the Company's internal control over financial reporting also excluded
XOOM.
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.
Philadelphia, Pennsylvania
February 28, 2019
(signed) KPMG LLP
99
Item 9B — Other Information
None.
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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.
Matthew Carter, Jr. has been a director of NRG since March 2018. Mr. Carter currently serves as Chief Executive Officer
of Aryaka Networks, Inc. Mr. Carter served as President and Chief Executive Officer and a director of Inteliquent, Inc., a publicly
traded provider of voice telecommunications services, from June 2015 until February 2017 when Inteliquent, Inc. was acquired.
He served as President of the Sprint Enterprise Solutions business unit of Sprint Corporation, a publicly traded telecommunications
company, from September 2013 until January 2015 and, previous to that position, served as President, Sprint Global Wholesale
& Emerging Solutions at Sprint Nextel Corporation. Mr. Carter also serves as a director of Jones Lang Lasalle Incorporated. He
previously served as a director of USG Corporation from 2012 to 2018, Apollo Education Group, Inc. from 2012 to 2017 and
Inteliquent, Inc. from June 2015 to February 2017 and has significant marketing, technology and international experience, including
previous management oversight for all of Inteliquent, Inc.’s operations.
Lawrence S. Coben has served as Chairman of the Board since February 2017, and has been a director of NRG since December
2003. He was Chairman and Chief Executive Officer of Tremisis Energy Corporation LLC until December 2017. Dr. Coben was
Chairman and Chief Executive Officer of both 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.
Heather Cox has been a director of NRG since March 2018. Ms. Cox currently serves as Chief Digital Health and Analytics
Officer at Humana Inc. Ms. Cox was Executive Vice President, Chief Technology & Digital Officer of United Services Automobile
Association, Inc. from October 2016 to March 2018. Ms. Cox served as Chief Executive Officer, Financial Technology Division
and Head of Citi FinTech of Citigroup, Inc. from November 2015 to September 2016, and as Chief Client Experience, Digital and
Marketing Officer, Global Consumer Bank of Citigroup, Inc. from April 2014 to November 2015. Prior to that, Ms. Cox served
at Capital One Financial Corporation for six years, most recently as Executive Vice President, US Card Operations, Capital One
from August 2011 to August 2014. Ms. Cox also served in various managerial and executive roles at E*Trade Bank for ten years.
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. Mr. Dallas is an “audit committee financial
expert” as defined by the SEC rules.
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
Clearway Energy, Inc. from December 2015 to May 2016 and Executive Vice President and Chief Operating Officer of Clearway
Energy, Inc. from December 2012 to December 2015. Mr. Gutierrez has also served on the board of Clearway Energy, Inc. from
December 2012 until August 2018. 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.
101
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.
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. Ms. Schaumburg has worked
in the Investment Banking industry for 28 years specializing in the power sector. She ran Credit Suisse's Power Group from 1994
- 1999, prior to its consolidation with Natural Resources and Project Finance, where she was responsible for assisting clients on
advisory and finance assignments. Her transaction expertise, across the spectrum of utility and unregulated power, includes mergers
and acquisitions, debt and equity capital market financings, project finance and leasing, utility disaggregation and privatizations.
Ms. Schaumburg is also a director of Brookfield Infrastructure Partners since 2008 and chair of the Audit Committee.
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.
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 also served as Executive Vice President, Chief Financial Officer of Clearway Energy, 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. Mr. Andrews serves on the board of RPM
International Inc. and previously served on the board of Clearway Energy, Inc. from December 2012 until August 2018. 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 Clearway
Energy, 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,
102
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.
Brian Curci has served as Senior Vice President, General Counsel of NRG since March 2018. Prior to March 2018, Mr.
Curci served as Deputy General Counsel and has served in various roles in over ten years with NRG, including as Corporate
Secretary from October 2011 to July 2018. Prior to NRG, Mr. Curci was a corporate associate with the law firm Saul Ewing LLP
in Philadelphia.
Robert Gaudette has served Senior Vice President, Business Solutions of NRG since December 2013. In this role, Mr.
Gaudette oversees NRG's broad portfolio of products and services for the commercial and industrial customers. Prior to December
2013, Mr. Gaudette was Senior Vice President C&I and Origination, starting in August 2013, and Senior Vice President - Product
Development & Origination following the acquisition of GenOn in December 2012. Mr. Gaudette served as Senior Vice President
and Chief Commercial Officer at GenOn from December 2010 to December 2012 and served as Vice President of Mirant's Mid-
Atlantic business unit from August 2009 to December 2010. During his career at Mirant, which began in 2001, Mr. Gaudette
worked in various other capacities including Director of West Power, Director of NYMEX Trading, Assistant to the Chief Operating
Officer and NYMEX natural gas trader.
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.
Other information required by this Item will be incorporated by reference to the similarly named section of NRG's Definitive
Proxy Statement for its 2019 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 2019 Annual Meeting of Stockholders.
103
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)
4,925,061 (1) $
520,182 (2)
5,445,243
$
21.15
25.85
23.22
11,495,799
— (4)
11,495,799 (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, 2018, there were
2,931,188 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
217,709 at a weighted-average exercise price of $34.13. See Item 15 — Note 19, Stock-Based Compensation, to Consolidated Financial Statements for a
discussion of the NRG GenOn LTIP.
(3) Consists of 8,564,611 shares of common stock under NRG's LTIP and 2,931,188 shares of treasury stock reserved for issuance under 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 19, 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 2019 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 2019 Annual Meeting of Stockholders.
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 2019 Annual Meeting of Stockholders.
104
Item 15 — Exhibits, Financial Statement Schedules
(a)(1) Financial Statements
PART IV
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, 2018, 2017, and 2016
Consolidated Statements of Comprehensive Income/(Loss) — Years ended December 31, 2018, 2017, and 2016
Consolidated Balance Sheets — As of December 31, 2018 and 2017
Consolidated Statements of Cash Flows — Years ended December 31, 2018, 2017, and 2016
Consolidated Statements of Stockholders' Equity — Years ended December 31, 2018, 2017, and 2016
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
105
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The the Stockholders and Board of Directors
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, 2018 and 2017, the related consolidated statements of operations, comprehensive income/(loss), stockholders' equity,
and cash flows for each of the years in the three year period ended December 31, 2018, 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, 2018 and 2017, and the results of its operations
and its cash flows for each of the years in the three year period ended December 31, 2018, 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, 2018, 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 February 28, 2019 expressed an unqualified opinion on the effectiveness of the Company's
internal control over financial reporting.
Change in Accounting Principle
As discussed in Note 2 to the consolidated financial statements, effective January 1, 2018, the Company has adopted Financial
Accounting Standard Board-Accounting Standards Codification Topic 606, Revenue from Contracts with Customers, and related
amendments.
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
February 28, 2019
106
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
Operating Income/(Loss)
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates
Impairment losses on investments
Other income, net
Loss on debt extinguishment, net
Interest expense
Total other expense
Income/(Loss) from Continuing Operations Before Income Taxes
Income tax expense/(benefit)
Net Income/(Loss) from Continuing Operations
(Loss)/income from discontinued operations, net of income tax
Net Income/(Loss)
Less: Net loss attributable to noncontrolling interests and redeemable
noncontrolling interests
Net Income/(Loss) Attributable to NRG Energy, Inc.
Dividends for preferred shares
Gain on redemption of preferred shares
Income/(Loss) Available for Common Stockholders
Earnings/(Loss) Per Share Attributable to NRG Energy, Inc. Common
Stockholders
Weighted average number of common shares outstanding — basic
Income/(loss) from continuing operations per weighted average common share — basic
(Loss)/income from discontinued operations per weighted average common share —
basic
Net Income/(Loss) per Weighted Average Common Share — Basic
$
$
$
$
Weighted average number of common shares outstanding — diluted
Income/(loss) from continuing operations per weighted average common share — diluted $
(Loss)/income from discontinued operations per weighted average common share —
diluted
$
Net Income/(Loss) per Weighted Average Common Share — Diluted
Dividends Per Common Share
$
$
See notes to Consolidated Financial Statements.
107
For the Year Ended December 31,
2018
2017
2016
$
9,478
$
9,074
$
8,915
7,108
421
99
799
90
11
8,528
—
32
982
9
(15)
18
(44)
(483)
(515)
467
7
460
(192)
268
—
268
—
—
268
6,886
596
1,534
836
44
22
9,918
87
16
(741)
(14)
(79)
51
(49)
(557)
(648)
(1,389)
(44)
(1,345)
(992)
(2,337)
(184)
(2,153)
—
—
(2,153) $
$
304
1.51
$
317
(3.66) $
(0.63) $
$
0.88
308
1.49
$
(0.62) $
$
0.87
0.12
$
(3.13) $
(6.79) $
317
(3.66) $
(3.13) $
(6.79) $
$
0.12
6,676
756
483
1,032
—
48
8,995
193
(80)
33
(18)
(268)
47
(142)
(583)
(964)
(931)
25
(956)
65
(891)
(117)
(774)
5
(78)
(701)
316
(2.42)
0.20
(2.22)
316
(2.42)
0.20
(2.22)
0.24
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
Net Income/(Loss)
Other Comprehensive (Loss)/Income, net of tax
Unrealized gain on derivatives, net of income tax expense of $0, $1, and $1
Foreign currency translation adjustments, net of income tax benefit of $0, $(2),
and $0
Available-for-sale securities, net of income tax expense of $0, $10, and $0
Defined benefit plan, net of income tax (benefit)/expense of $0, $(21), and $0
Other comprehensive (loss)/income
Comprehensive Income/(Loss)
Less: Comprehensive income/(loss) 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
For the Year Ended December 31,
2018
2017
2016
(In millions)
$
268
$
(2,337) $
(891)
23
(11)
1
(35)
(22)
246
14
232
—
—
13
12
(8)
46
63
(2,274)
(179)
(2,095)
—
—
35
(1)
1
3
38
(853)
(117)
(736)
5
(78)
(663)
Comprehensive Income/(Loss) Available for Common Stockholders
$
232
$
(2,095) $
See notes to Consolidated Financial Statements.
108
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
Prepayments and other current assets
Current assets - held-for-sale
Current assets - discontinued operations
Total current assets
Property, plant and equipment, net
Other Assets
Equity investments in affiliates
Goodwill
Intangible assets, net
Nuclear decommissioning trust fund
Derivative instruments
Deferred income taxes
Other non-current assets
Non-current assets - held-for-sale
Non-current assets - discontinued operations
Total other assets
Total Assets
See notes to Consolidated Financial Statements.
As of December 31,
2018
2017
(In millions)
563
33
17
1,019
412
764
287
5
302
1
197
3,600
3,048
412
573
591
663
317
46
289
77
1,012
3,980
10,628
$
$
770
37
279
900
453
624
171
180
163
116
744
4,437
5,974
182
539
507
692
159
6
310
43
10,506
12,944
23,355
$
$
109
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 expenses and other current liabilities
Accrued expenses and other current liabilities - affiliate
Current liabilities - held for sale
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
Derivative instruments
Deferred income taxes
Out-of-market contracts, net
Other non-current liabilities
Non-current liabilities - held-for-sale
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; 420,288,886 and
418,323,134 shares issued; and 283,650,039 and 316,743,089 shares outstanding at
December 31, 2018 and 2017
Additional paid-in capital
Accumulated deficit
Treasury stock, at cost; 136,638,847 and 101,580,045 shares at December 31, 2018
and 2017
Accumulated other comprehensive loss
Noncontrolling interest
Total Stockholders' Equity
Total Liabilities and Stockholders' Equity
See notes to Consolidated Financial Statements.
As of December 31,
2018
2017
(In millions, except share data)
$
72
862
1
673
33
680
—
5
72
2,398
6,449
282
371
435
304
65
121
718
65
635
9,445
11,843
19
4
8,510
(6,022)
(3,632)
(94)
—
(1,234)
10,628
$
204
684
57
537
37
756
161
72
846
3,354
9,180
269
415
458
143
21
129
534
8
6,798
17,955
21,309
78
4
8,376
(6,268)
(2,386)
(72)
2,314
1,968
23,355
$
$
110
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Year Ended December 31,
2017
2016
2018
Cash Flows from Operating Activities
Net income/(loss)
(Loss)/income from discontinued operations, net of income tax
Income/(loss) from continuing operations
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates
Depreciation, amortization and accretion
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/cost 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 risk management activities
Changes in nuclear decommissioning trust liability
GenOn settlement, net of insurance proceeds
Net loss on deconsolidation of Agua Caliente and Ivanpah projects
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 provided by discontinued operations
Net Cash Provided by Operating Activities
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired
Capital expenditures
Proceeds from renewable energy grants
Net proceeds from sale/(purchases) 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 of cash disposed and sale of discontinued operations, net of fees
Deconsolidation of Agua Caliente and Ivanpah projects
Changes in investments in unconsolidated affiliates
Net (contributions to)/distributions from discontinued operations
Other
Cash provided/(used) by continuing operations
Cash used by discontinued operations
Net Cash Used by Investing Activities
(In millions)
$
268
$
(2,337) $
(891)
(192)
460
(992)
(1,345)
65
(956)
46
459
85
48
29
44
45
25
(49)
114
37
5
(105)
60
(63)
13
(83)
31
(41)
113
(166)
(104)
1,003
374
1,377
(243)
(388)
—
19
(572)
513
1,564
(268)
(39)
(60)
(6)
520
(725)
(205)
102
596
68
51
29
49
54
35
(9)
1,614
(170)
13
(80)
11
—
—
(83)
143
(187)
44
(88)
9
856
754
1,610
(14)
(254)
8
66
(512)
501
430
—
(57)
150
22
340
(979)
(639)
67
772
45
49
33
142
68
10
139
751
16
(12)
396
41
—
—
24
60
(120)
(59)
(61)
32
1,437
471
1,908
—
(544)
36
(1)
(551)
510
241
—
(33)
(58)
31
(369)
(388)
(757)
111
For the Year Ended December 31,
2017
2016
2018
Cash Flows from Financing Activities
Payments of dividends to preferred and common stockholders
Payments for treasury stock
Payments for preferred shares
Payments for debt extinguishment costs
Net distributions to noncontrolling interest from subsidiaries
Proceeds/(payments) from issuance of common stock
Proceeds from issuance of long-term debt
Payments of debt issuance costs
Payments for short and long-term debt
Receivable from affiliate
Other
Cash used by continuing operations
Cash provided/(used) 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 (Decrease)/Increase 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)
(37)
(1,250)
—
(32)
(16)
21
1,100
(19)
(1,734)
(26)
(4)
(1,997)
471
(1,526)
1
120
(473)
1,086
(38)
—
—
(42)
(30)
(2)
1,178
(18)
(1,884)
(125)
(8)
(969)
(169)
(1,138)
(1)
(394)
226
860
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period
$
613
$
1,086
$
See notes to Consolidated Financial Statements.
(76)
—
(226)
(121)
(27)
1
4,412
(61)
(5,146)
—
(7)
(1,251)
483
(768)
1
566
(182)
1,042
860
112
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Common
Stock
Additional
Paid-In
Capital
Accumulated
Deficit
Treasury
Stock
Accumulated
Other
Comprehensive
Loss
Noncon-
trolling
Interest
Total
Stock-
holders'
Equity
(In millions)
Balances at December 31, 2015
$
4
$
8,296
$
(3,007) $ (2,413) $
(173) $
2,727
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
38
(79)
(16)
14
59
(2)
5
(774)
(6)
1
(74)
(5)
78
(158)
(92)
30
(7)
5,434
(853)
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
Net income
Other comprehensive loss
Sale of assets to NRG Yield, Inc.
ESPP share purchases
Share repurchases
Equity-based compensation
Common stock dividends
Distributions to noncontrolling interests
Dividends paid to NRG Yield, Inc.
Contributions from noncontrolling interests
Adoption of new accounting standards
Sale of NRG Yield and other business
(22)
4
(1,250)
8
(2)
27
268
(37)
15
Equity component of convertible senior notes
101
26
8
(43)
(61)
304
294
(22)
16
2
(1,250)
27
(37)
(43)
(61)
304
15
(2,548)
(2,548)
101
Balances at December 31, 2018
$
4
$
8,510
$
(6,022) $ (3,632) $
(94) $
— $
(1,234)
See notes to Consolidated Financial Statements.
113
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 — Nature of Business
General
NRG Energy, Inc., or NRG or the Company, is an energy company built on dynamic retail brands with diverse generation
assets. NRG brings the power of energy to consumers 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. NRG is
perfecting the integrated model by balancing retail load with generation supply within its deregulated markets, while evolving to
a customer-driven business. The Company sells energy, services, and innovative, sustainable products and services directly to
retail customers under the names "NRG" and "Reliant" and other brand names owned by NRG supported by approximately 23,000(a)
MW of generation as of December 31, 2018.
Retail is a consumer facing business that includes residential and small commercial (Mass Market) consumers and the
Company's Business Solutions group, which includes demand response, commodity sales, energy efficiency and energy
management solutions. 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.
The Company's Generation business includes plant operations, commercial operations, EPC, asset management, energy
services and other critical related functions. In addition to the traditional functions from NRG's wholesale power generation
business, Generation also includes NRG's retained renewable generation business.
Discontinued Operations
On December 31, 2018, as described in Note 3, Acquisitions, Discontinued Operations and Dispositions, the
Company concluded that the sale of its South Central Portfolio to Cleco, excluding the Cottonwood facility, met held-for-sale
criteria and should be presented as a discontinued operation, as the sale represented a strategic shift in the business in which NRG
operates. The financial information for all historical periods has been recast to reflect the presentation of these entities as
discontinued operations.
On August 31, 2018, as described in Note 3, Acquisitions, Discontinued Operations and Dispositions, NRG deconsolidated
NRG Yield, Inc. and its Renewables Platform for financial reporting purposes. The financial information for all historical periods
has been recast to reflect the presentation of these entities, as well as the Carlsbad project, as discontinued operations. As a result
of the sale of NRG Yield, the Company no longer controls the Agua Caliente project. Due to this change in control, the Company
has deconsolidated the Agua Caliente project from its financial results and has accounted for the project as an equity method
investment.
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 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. GenOn's plan of reorganization was confirmed on December
14, 2018.
(a) excluding discontinued operations and held for sale
114
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 U.S. 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.
Net Income/(Loss) attributable to NRG Energy, Inc.
The following table reflects the net income/(loss) attributable to NRG Energy, Inc. after removing the net loss attributable
to the noncontrolling interest and redeemable noncontrolling interest:
Income/(loss) from continuing operations, net of income tax
Loss from discontinued operations, net of income tax
Net income/(loss) attributable to NRG Energy, Inc. stockholders
Segment Reporting
Year Ended December 31,
2018
2017
2016
(In millions)
$
(977) $
(1,176)
465
(197)
268
$
(2,153)
$
$
(733)
(41)
(774)
The Company's businesses are segregated into the Generation, Retail and corporate segments. Generation includes all power
plant activities, domestic and international, as well as renewables. Retail includes Mass customers and Business Solutions, which
includes C&I customers and other distributed and reliability products.
As described in Note 3, Acquisitions, Discontinued Operations and Dispositions, the Company has determined that the South
Central Portfolio, NRG Yield Inc. and its Renewables Platform, Carlsbad, and GenOn all qualified for treatment as a discontinued
operation. The financial information for all historical periods has been recast to reflect the presentation of discontinued operations
within the corporate segment.
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.
115
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 sheets that sum to the total of the same such amounts shown in the statements
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 statements of cash flows
Year Ended December 31,
2018
2017
2016
(In millions)
563
$
770
$
33
17
37
279
613
$
1,086
$
$
$
591
2
267
860
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.
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, 2018 and 2017, the allowance for doubtful accounts was $32 million and $28 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.
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.
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.
116
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 9, 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, 2018, 2017, and 2016, was $7 million, $20
million, and $29 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. 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, 2018 and 2017, the Company had accumulated amortization related to its
intangible assets of $1.2 billion and $1.6 billion, respectively.
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 refer to Note 10, 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.
117
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, 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 18, Income Taxes, changes to existing net deferred tax assets
or valuation allowances or changes to uncertain tax benefits, are recorded to income tax expense.
Revenue Recognition
Revenue from Contracts with Customers
On January 1, 2018, the Company adopted the guidance in ASC 606 using the modified retrospective method applied to
contracts that were not completed as of the adoption date. The Company recognized the cumulative effect of initially applying the
new standard as a credit to the opening balance of accumulated deficit, resulting in a decrease of approximately $15 million. The
adjustment primarily related to costs incurred to obtain a contract with customers and customer incentives. Following the adoption
of the new standard, the Company’s revenue recognition of its contracts with customers remains materially consistent with its
historical practice. The comparative information has not been restated and continues to be reported under the accounting standards
in effect for those periods. The Company's policies with respect to its various revenue streams are detailed below. In general, the
Company applies the invoicing practical expedient to recognize revenue for the revenue streams detailed below, except in
circumstances where the invoiced amount does not represent the value transferred to the customer.
Retail Revenues
Gross revenues for energy sales and services to retail customers are recognized as the Company transfers the promised goods
and services to the customer. For the majority of its electricity contracts, the Company’s performance obligation with the customer
is satisfied over time and performance obligations for its electricity products are recognized as the customer takes possession of
the product. The Company also allocates the contract consideration to distinct performance obligation in a contract for which the
timing of the revenue recognized is different. Additionally, customer discounts and incentives reduce the contract consideration
and are recognized over the term of the contract.
Energy sales and services that have been delivered but not billed by period end are estimated. 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.
118
As contracts for retail electricity can be for multi-year periods, the Company has performance obligations under these
contracts that have not yet been satisfied. These performance obligations have transaction prices that are both fixed and variable,
and that vary based on the contract duration, customer type, inception date and other contract-specific factors. For the fixed price
contracts, the amount of any unsatisfied performance obligations will vary based on customer usage, which will depend on factors
such as weather and customer activity and therefore it is not practicable to estimate such amounts.
Energy Revenue
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 over time, using the output method for measuring
progress of satisfaction of performance obligations. 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. The Company applies the invoicing
practical expedient, where applicable, in recognizing energy revenue. Under the practical expedient, revenue is recognized based
on the invoiced amount which is equal to the value to the customer of NRG’s performance obligation completed to date. 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 Revenue
Capacity revenues consist of revenues billed to a third party at either the market or a negotiated contract price for making
installed generation and demand response capacity available in order to satisfy system integrity and reliability requirements.
Capacity revenues are recognized over time, using the output method for measuring progress of satisfaction of performance
obligations. The Company applies the invoicing practical expedient, where applicable, in recognizing capacity revenue. Under
the practical expedient, revenue is recognized based on the invoiced amount which is equal to the value to the customer of NRG’s
performance obligation completed to date.
Capacity revenue contracts mainly consist of:
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. As of December 31, 2018, estimated future revenues for cleared auction MWs in the various capacity auctions
are $618 million, $481 million, $532 million, and $244 million for fiscal years 2019, 2020, 2021 and 2022, respectively.
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. 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 and New York, capacity and contracted revenues are through
bilateral contracts with third parties of our Retail segment.
Renewable Energy Credits
Renewable energy credits are usually sold through long-term contracts. Revenue from the sale of self-generated RECs is
recognized when related energy is generated and simultaneously delivered even in cases where there is a certification lag as it has
been deemed to be perfunctory.
In a bundled contract to sell energy, capacity and/or self-generated RECs, all performance obligations are deemed to be
delivered at the same time and hence, timing of recognition of revenue for all performance obligations is the same and occurs over
time. In such cases, it is often unnecessary to allocate transaction price to multiple performance obligations.
Sale of Emission Allowances
The Company records its inventory of emission allowances as part of intangible assets. From time to time, management may
authorize the transfer of emission allowances in excess of expected 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.
119
Disaggregated Revenues
The following table represents the Company’s disaggregation of revenue from contracts with customers for the year ended
December 31, 2018, along with the reportable segment for each category:
(In millions)
Energy revenue(a)
Capacity revenue(a)
Retail revenue
Mass customers
Business Solutions customers
Total retail revenue
Mark-to-market for economic hedging activities(b)
Other revenue(a)(c)
Total operating revenue
Less: Lease revenue
Less: Derivative revenue
For the Year Ended December 31, 2018
Retail
Texas
Generation
East/West/
Other
Subtotal
Corporate/
Eliminations
Total
$
— $ 1,585
$
1,092
$ 2,677
$
(1,129) $
1,548
—
5,618
1,492
7,110
(7)
—
7,103
13
(7)
1
—
—
—
(174)
84
1,496
—
2,160
669
670
—
—
—
(28)
203
1,936
8
193
—
—
—
(202)
287
3,432
8
2,353
—
(5)
—
(5)
79
(2)
(1,057)
—
(1,037)
670
5,613
1,492
7,105
(130)
285
9,478
21
1,309
Total revenue from contracts with customers
$
7,097
$
(664) $
1,735
$ 1,071
$
(20) $
8,148
(a) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815:
Energy revenue
Capacity revenue
Other revenue
Retail
Texas
East/West/
Other
$
$
— $ 2,332
—
—
2
—
69
138
14
Subtotal
$ 2,401
138
16
Corporate/
Eliminations
$
(1,117) $
—
—
Total
1,284
138
16
(b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815
(c) Included in other revenue is lease revenue of $17 million and $5 million for Retail and East/West/Other, respectively
Contract Amortization
Assets and liabilities recognized 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.
Lease Revenue
Certain of the Company’s revenues are obtained through leases of rooftop residential solar systems, which are accounted
for as operating leases in accordance with ASC 840, Leases. Pursuant to the lease agreements, the customers’ monthly payments
are pre-determined fixed monthly amounts and may include an annual fixed percentage escalation to reflect the impact of utility
rate increases over the lease term, which is 20 years. The Company records operating lease revenue on a straight-line basis over
the life of the lease term. Certain customers made initial down payments that are being amortized over the life of the lease. The
difference between the payments received and the revenue recognized is recorded as deferred revenue.
120
Contract Balances
The following table reflects the contract assets and liabilities included in the Company's balance sheet as of
December 31, 2018:
Deferred customer acquisition costs
Accounts receivable, net - Contracts with customers
Accounts receivable, net - Derivative instruments
Total accounts receivable, net
Unbilled revenues (included within Accounts receivable, net - Contracts with customers)
Deferred revenues
(In millions)
111
1,002
20
1,022
392
67
$
$
$
$
The Company's customer acquisition costs consist of broker fees, commission payments and other costs that represent
incremental costs of obtaining the contract with customers for which the Company expects to recover. The Company amortizes
these amounts over the estimated life of the customer contract. As a practical expedient, the Company expenses the incremental
costs of obtaining a contract if the amortization period of the asset would have been one year or less.
When the Company receives consideration from the customer that is in excess of the amount due, such consideration is
reclassified to deferred revenue, which represents a contract liability. Generally, the Company will recognize revenue from contract
liabilities in the next period as the Company satisfies its performance obligations.
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, 2018, 2017, and 2016 was $104 million, $253 million, and $272 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, 2018, 2017, and 2016, the Company's
revenues and cost of operations included gross receipts taxes of $99 million, $92 million, and $101 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.
Cost of Energy for Retail 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 $105 million, $107 million, and $90
million as of December 31, 2018, 2017, and 2016, 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.
121
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, 2018, 2017, and 2016, amounts recognized as foreign currency transaction gains
(losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31, 2018, 2017, and 2016
were $(13) million, $(2) million and $(11) million, respectively.
Concentrations of Credit Risk
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.
Fair Value of Financial Instruments
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.
122
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 12 , 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 assist in determining 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.
Investments Accounted for by the Equity Method
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. 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.
123
Tax Equity Arrangements
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, 2018, 2017, and 2016.
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
Distributions to redeemable noncontrolling interest
Contributions from redeemable noncontrolling interest
Non-cash adjustments to redeemable noncontrolling interest
Net income attributable to redeemable noncontrolling interest - continuing operations
Net loss attributable to redeemable noncontrolling interest - discontinued operations
Sale of NRG Yield and the Renewables Platform(a)
Balance as of December 31, 2018
(In millions)
$
$
29
(1)
33
23
(38)
46
(2)
99
7
(72)
78
(3)
26
(8)
1
(27)
(48)
19
(a) See Note 3, Acquisitions, Discontinued Operations and Dispositions, for further information regarding the sale of NRG Yield and its Renewables Platform
Sale-Leaseback Arrangements
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.
124
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.
As described in Note 3, Acquisitions, Discontinued Operations and Dispositions, the Company entered into an agreement
to leaseback the Cottonwood facility upon the close of the South Central Portfolio transaction. The lease will be accounted for as
an operating lease and accordingly, a right of use asset and lease liability will be set up on the lease commencement date which
will be amortized through the end of the lease.
Marketing and Advertising Costs
The Company expenses its marketing and advertising costs as incurred and which are included within selling, general and
administrative expenses. 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, 2018, 2017, and 2016 were $73 million,
$66 million, and $79 million, respectively.
Reorganization Costs
Reorganization costs include costs incurred by the Company related to the Transformation Plan implementation and primarily
reflect severance and contract modifications. As of December 31, 2018 and December 31, 2017, $90 million and $44 million were
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.
125
Recent Accounting Developments - Guidance Adopted in 2018
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.
Previous 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 did not have a material impact on the Company's results of operations, cash flows, and statement of financial
position.
ASU 2016-01 - In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments - Overall (Subtopic 825-10):
Recognition and Measurement of Financial Assets and Financial Liabilities, or ASU No. 2016-01. The amendments of ASU No.
2016-01 eliminate available-for-sale classification of equity investments and require that equity investments (except those
accounted for under the equity method of accounting, or those that result in consolidation of the investee) be generally measured
at fair value with changes in fair value recognized in net income. Further, the amendments require that financial assets and financial
liabilities be presented separately in the notes to the financial statements, grouped by measurement category and form of financial
asset. The guidance in ASU No. 2016-01 is effective for financial statements issued for fiscal years beginning after December 15,
2017, and interim periods within those annual periods. The Company adopted the amendments of ASU No. 2016-01 effective
January 1, 2018. In connection with the adoption of the standard, the Company has applied the guidance on a modified retrospective
basis, which resulted in no material adjustments recorded to the consolidated results of operations, cash flows, and statement of
financial position.
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, did 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 has been disclosing since the date of adoption.
Recent Accounting Developments - Guidance Not Yet Adopted
ASU 2018-17 - In October 2018, the FASB issued ASU No. 2018-17, Consolidations (Topic 810): Targeted Improvements to
Related Party Guidance for Variable Interest Entities, in response to stakeholders’ observations that Topic 810, Consolidations,
could be improved thereby improving general purpose financial reporting. Specifically, ASC 2018-17 requires application of the
variable interest entity (VIE) guidance to private companies under common control and consideration of indirect interest held
through related parties under common control for determining whether fees paid to decision makers and service providers are
variable interests. The amendments are effective for fiscal years beginning after December 15, 2019, and interim periods within
those fiscal years. All entities are required to apply the amendments retrospectively with a cumulative-effect adjustment to retained
earnings at the beginning of the earliest period presented. The Company is evaluating the impact of adopting this guidance on the
consolidated financial statements and disclosures.
ASU 2018-13 - In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure
Framework - Changes to the Disclosure Requirement for Fair value Measurement), or ASU No. 2018-13. The guidance in ASU
No. 2018-13 eliminates such disclosures as the amount of and reasons for transfers between Level 1 and Level 2 of the fair
value hierarchy. The amendments in ASU No. 2018-13 add new disclosure requirements for Level 3 measurements. ASU No.
2018-13 is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with
early adoption permitted for any eliminated or modified disclosures. Certain disclosures in ASU No. 2018-13 are required to be
126
applied on a retrospective basis and others on a prospective basis. As the amendment contemplates changes in disclosures only,
it will have no material impact on the Company's results of operations, cash flows, or 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 adopted the standard and its subsequent
corresponding updates effective January 1, 2019 under the modified retrospective approach by applying the provisions of the
new leases guidance at the effective date without adjusting the comparative periods presented. The Company has assessed its
leasing arrangements and evaluated the impact of applying practical expedients and accounting policy elections. The Company
implemented lease accounting software to meet the reporting requirements of the standard and identified changes to its business
processes and controls to support recognition and disclosure under the new standard. Management estimates operating lease
liabilities will increase between $380 million and $420 million and right-of-use assets between $300 million and $340 million
will be established upon adoption, before considering deferred taxes. Management does not believe the adoption of Topic 842
will have a material impact on the statements of operations or cash flows.
Note 3 — Acquisitions, Discontinued Operations and Dispositions
Acquisitions
XOOM Energy Acquisition — On June 1, 2018, the Company completed the acquisition of XOOM Energy, LLC, an electricity
and natural gas retailer operating in 19 states, Washington, D.C. and Canada, for approximately $213 million in cash. The acquisition
increased NRG's retail portfolio by approximately 300,000 customers. The purchase price was allocated as follows:
Net current and non-current working capital
Other intangible assets
Goodwill
XOOM Purchase Price
(In millions)
46
133
34
213
$
$
Small Book Acquisitions — Through the end of December 2018, the Company has agreed to acquire several books of
customers totaling approximately 115,000 customers, along with brand names, for $44 million, the majority of which was
allocated to acquired intangibles.
Discontinued Operations
Sale of South Central Portfolio
On February 4, 2019, the Company completed the sale of its South Central Portfolio to Cleco. The Company concluded
that the divested business met the criteria for discontinued operations, as the disposition represents a strategic shift in the business
in which NRG operates and held-for-sale criteria as of December 31, 2018. As such, all prior period results for the operations of
the South Central Portfolio have been reclassified as discontinued operations. In connection with the transaction, NRG also entered
into a transition services agreement to provide certain corporate services to the divested business.
The South Central Portfolio includes the 1,263 MW Cottonwood natural gas generating facility. Upon the closing of the
sale of the South Central Portfolio, NRG entered into a lease agreement with Cleco to leaseback the Cottonwood facility through
2025. Due to its continuing involvement with the Cottonwood facility, NRG will not use held-for-sale or discontinued operations
treatment in accounting for historical and ongoing activity with Cottonwood.
127
Summarized results of South Central discontinued operations were as follows:
(In millions)
Operating revenues
Operating costs and expenses
Other income
Gain from discontinued operations, net of tax
Year Ended December 31,
2018
410
(346)
2
66
$
$
2017
422
(335)
—
87
$
$
2016
467
(395)
—
72
$
$
The following table summarizes the major classes of assets and liabilities classified as discontinued operations of South
Central as follows:
(In millions)
Cash and cash equivalents
Accounts receivable, net
Inventory
Other current assets
Current assets - discontinued operations
Property, plant and equipment, net
Other non-current assets
Non-current assets - discontinued operations
Accounts payable
Other current liabilities
Current liabilities - discontinued operations
Out-of-market contracts, net
Other non-current liabilities
Non-current liabilities - discontinued operations
December 31, 2018
December 31, 2017
$
$
89
49
35
5
178
408
1
409
19
5
24
50
11
61
$
$
(3)
61
33
—
91
461
1
462
28
6
34
66
10
76
Sale of Ownership in NRG Yield, Inc. and its Renewables Platform
On August 31, 2018, the Company completed the sale of its ownership interests in NRG Yield, Inc. and its Renewables
Platform to GIP for total cash consideration of $1.348 billion. The Company concluded that the divested businesses met the criteria
for discontinued operations, as the dispositions represented a strategic shift in the business in which NRG operates. As such, all
prior period results for the transaction have been reclassified as discontinued operations. In connection with the transaction, NRG
entered into a transition services agreement to provide certain corporate services to the divested businesses.
As a result of the sale of NRG Yield, Inc., the Company's indirect ownership interest in the Agua Caliente solar project was
reduced from 51% to 35%. As such, the Company no longer controls the project; and accordingly, no longer consolidates the
project for financial reporting purposes. The Company recorded its ownership interest as an equity method investment upon
deconsolidation resulting in a gain of $8 million.
As part of the agreement to sell NRG Yield and the Renewables Platform, the Company agreed to indemnify NRG Yield for
any increase in property taxes for certain solar properties. The indemnity term will expire at various dates between 2029 and 2039.
NRG has determined that the payment of this indemnity is probable and has recorded the estimated present value of the obligation
as of the closing date of the transaction of $153 million to other non-current liabilities with a corresponding loss from discontinued
operations. In addition to the California property tax indemnity, there were additional commitments and advisory fees totaling
approximately $50 million. The Company will also retain all costs associated with the development and ownership of the Patriot
Wind project until its sale to a third party pursuant to a sale agreement.
128
Carlsbad
On February 6, 2018, NRG entered into an agreement with NRG Yield and GIP to sell 100% of the membership interests in
Carlsbad Energy Holdings LLC, which owned the Carlsbad project, for $387 million of cash consideration, excluding working
capital adjustments. The primary condition to close the Carlsbad transaction was the completion of the sale of NRG Yield and the
Renewables Platform. As the sale of NRG Yield and the Renewables Platform has closed, the Company concluded that the Carlsbad
project met the criteria for discontinued operations and accordingly, the financial information for all current and historical periods
has been recast to reflect Carlsbad as a discontinued operation. The Company continued to consolidate Carlsbad for financial
reporting purposes until the transaction closed on February 27, 2019. Carlsbad will continue to have a ground lease and easement
agreement with NRG. The agreement has an initial term ending in 2039 with two ten year extensions. As a result of the transaction,
additional commitments related to the project totaled $23 million.
Summarized results of NRG Yield, Inc. and Renewables Platform and Carlsbad discontinued operations were as follows:
(In millions)
Operating revenues
Operating costs and expenses
Other expenses
Gain/(loss) from operations of discontinued components, before tax
Income tax expense/(benefit)
Gain/(loss) from discontinued operations, net of tax
Loss on deconsolidation, net of tax
California property tax indemnification
Other Commitments, Indemnification and Fees
Loss on disposal of discontinued operations, net of tax
Loss from discontinued operations, net of tax
Year Ended December 31,
$
2018
909
(661)
(174)
74
4
70
(134)
(153)
(75)
(362)
(292) $
$
2017
1,164
(1,114)
(288)
(238)
52
(290)
—
—
—
—
(290) $
2016
1,165
(1,023)
(261)
(119)
(20)
(99)
—
—
—
—
(99)
$
$
129
The following table summarizes the major classes of assets and liabilities classified as discontinued operations as follows:
December 31, 2018 (a)
December 31, 2017 (b)
(In millions)
Cash and cash equivalents
Restricted Cash
Accounts receivable, net
Other current assets
Current assets - discontinued operations
Property, plant and equipment, net
Equity investments in affiliates
Intangible assets, net
Other non-current assets
Non-current assets - discontinued operations
Current portion of long term debt and capital leases
Accounts payable
Other current liabilities
Current liabilities - discontinued operations
Long-term debt and capital leases
Other non-current liabilities
$
— $
4
10
5
19
590
—
9
4
603
20
27
1
48
572
2
224
229
119
81
653
7,473
856
1,240
475
10,044
484
169
159
812
6,536
186
6,722
Non-current liabilities - discontinued operations
$
574
$
(a) Represents the Carlsbad project
(b) Represents the discontinued operations of NRG Yield, NRG's Renewable Platform and the Carlsbad project
Sale of Assets to NRG Yield, Inc. Prior to Discontinued Operations
On June 19, 2018, the Company completed the UPMC Thermal Project and received cash consideration from NRG Yield of
$84 million plus an additional $3 million received at final completion in January 2019.
On March 30, 2018, as part of the Transformation Plan, the Company sold to NRG Yield, Inc. 100% of NRG's interests in
Buckthorn Renewables, LLC, which owns a 154 MW construction-stage utility-scale solar generation project, located in Texas.
NRG Yield, Inc. paid cash consideration of approximately $42 million, excluding working capital adjustments, and assumed non-
recourse debt of approximately $183 million.
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.
GenOn
On June 14, 2017, 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 controlled GenOn as it was subject to
the control of the Bankruptcy Court; and, accordingly, NRG deconsolidated GenOn and its subsidiaries for financial reporting
purposes as of such date.
By eliminating a large portion of its operations in the PJM market with the deconsolidation of GenOn, NRG concluded that
GenOn met the criteria for discontinued operations, as this represented a strategic shift in the business in which NRG operated.
As such, all prior period results for GenOn have been reclassified as discontinued operations.
130
Year Ended December 31,
2018
2017
2016
Summarized results of discontinued operations were as follows:
(In millions)
Operating revenues
Operating costs and expenses
Gain on sale of assets
Other expenses
(Loss)/gain from operations of discontinued components, before tax
Income tax expense
(Loss)/gain from discontinued operations
Interest income - affiliate
Income/(loss) from discontinued operations, net of tax
Pre-tax loss on deconsolidation
Settlement consideration, insurance and services credit
Pension and post-retirement liability assumption
Other
Income/(loss) on disposal of discontinued operations, net of tax
$
— $
—
—
—
—
—
—
3
3
—
63
21
(53)
31
Income/(loss) from discontinued operations, net of tax
$
34
$
GenOn Settlement and Plan Confirmation
$
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
Effective July 16, 2018, NRG and GenOn consummated the GenOn Settlement whereby the Company paid GenOn
approximately $125 million, which included (i) the settlement consideration of $261 million, (ii) the transition services credit of
$28 million and (iii) the return of $15 million of collateral posted to NRG; offset by the (i) $151 million in borrowings under the
intercompany secured revolving credit facility, (ii) related accrued interest and fees of $12 million, (iii) remaining payments due
under the transition services agreement of $10 million, (iv) $4 million reduction of the settlement payment related to NRG assigning
to GenOn approximately $8 million of historical claims against REMA and (v) certain other balances due to NRG totaling $2
million.
GenOn's plan of reorganization was confirmed on December 14, 2018. Pursuant to the confirmed plan, NRG retained the
pension liability for GenOn employees for service provided prior to the completion of the reorganization. NRG also retained the
liability for GenOn's post-employment and retiree health and welfare benefits. These liabilities were recorded within other non-
current liabilities as of December 31, 2018 and 2017. As a result of GenOn's emergence from bankruptcy, NRG is taking a deduction
for GenOn tax losses of $9.5 billion, including a worthless stock deduction.
Other than those obligations which survive or are independent of the releases described herein, the GenOn Settlement and
the GenOn Chapter 11 plan provide NRG releases from GenOn and each of its debtor and non-debtor subsidiaries.
REMA Plan of Reorganization
On October 16, 2018, REMA and its subsidiaries filed voluntary petitions for chapter 11 relief and a prepackaged plan of
reorganization in the United States Bankruptcy Court for the Southern District of Texas. The REMA debtors' plan of reorganization
has been formally accepted by REMA's voting creditors and is consistent with the releases NRG received under the GenOn
Settlement and the GenOn plan.
131
GenMA Settlement
The Bankruptcy Court order confirming the plan of reorganization also approved the settlement terms agreed to among the
GenOn Entities, NRG, the Consenting Holders, GenOn Mid-Atlantic, and certain of GenOn Mid-Atlantic’s stakeholders, or the
GenMA Settlement, and directed the settlement parties to cooperate in good faith to negotiate definitive documentation consistent
with the GenMA Settlement term sheet in order to pursue consummation of the GenMA Settlement. The definitive documentation
effectuating the GenMA Settlement was finalized and effective as of April 27, 2018. Certain terms of the compromise with respect
to NRG and GenOn Mid-Atlantic are as follows:
Settlement of all pending litigation and objections to the Plan (including with respect to releases and feasibility);
•
• NRG provided $38 million in letters of credit as new qualifying credit support to GenOn Mid-Atlantic; and
• NRG paid approximately $6 million as reimbursement of professional fees incurred by certain of GenOn Mid-Atlantic's
stakeholders in connection with the GenMA Settlement.
Planned Dispositions
On November 1, 2018, the Company offered to Clearway Energy, Inc. its ownership interest in Agua Caliente Borrower 1,
LLC, for approximately $120 million, which owns a 35% interest in Agua Caliente, a 290 MW utility-scale solar project located
in Dateland, Arizona. The offer expired on January 31, 2019, with no action taken by Clearway Energy, Inc. As a result, the right
of first offer agreement with Clearway Energy, Inc. has expired and NRG's interest in Agua Caliente is no longer subject to a right
of first offer thereunder.
Dispositions
On August 1, 2018, the Company completed the sale of 100% of its ownership interests in BETM to Diamond Energy Trading
and Marketing, LLC for $71 million, net of working capital adjustments, which resulted in a gain of $15 million on the sale. The
sale also resulted in the release and return of approximately $119 million of letters of credit, $32 million of parent guarantees, and
$4 million of net cash collateral to NRG.
On June 29, 2018, the Company completed the sale of Canal 3 to Stonepeak Kestrel for cash proceeds of approximately
$16 million and recorded a gain of $17 million. Prior to the sale, Canal 3 entered into a financing arrangement and received
cash proceeds of $167 million, of which $151 million was distributed to the Company. The related debt was non-recourse to
NRG and was transferred to Stonepeak Kestrel in connection with the sale of Canal 3.
In addition, the Company completed other asset sales for $28 million of cash proceeds during the year ended December
31, 2018.
2016 Dispositions
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 $3 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 $103 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 $6 million remains as of December 31, 2018.
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. The Company's remaining 23.7% interest in EVgo is accounted
for as an equity method investment.
132
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 9, Asset Impairments.
Note 4 — Fair Value of Financial Instruments
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.
The estimated carrying values and fair values of the Company's recorded financial instruments not carried at fair market
value are as follows:
Assets
Notes receivable
Liabilities
Long-term debt, including current portion (a)
As of December 31,
2018
2017
Carrying Amount
Fair Value
Carrying Amount
Fair Value
(In millions)
$
$
17
6,591
$
$
14
6,697
$
$
2
9,482
$
$
2
9,739
(a) 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, 2018 and 2017:
Long-term debt, including current portion
$
6,528
$
(In millions)
$
169
7,432
$
2,307
As of December 31, 2018
As of December 31, 2017
Level 2
Level 3
Level 2
Level 3
133
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.
Recurring Fair Value Measurements
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
sheets on a recurring basis and their level within the fair value hierarchy:
As of December 31, 2018
Fair Value
Total
Level 1
Level 2
Level 3
(In millions)
Investments in securities (classified within other current and non-current
assets)
$
39
$
2
$
18
$
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-nuclear trust fund investments
Equity securities
Total assets
Derivative liabilities:
Commodity contracts
Total liabilities
134
19
46
100
22
96
312
4
1
1,042
39
64
8
1,792
977
977
$
$
$
$
$
$
19
46
—
—
—
312
—
1
137
—
—
—
517
224
224
—
—
100
22
96
—
4
—
796
39
—
—
1,075
664
664
$
$
$
$
$
$
19
—
—
—
—
—
—
—
—
109
—
—
—
128
89
89
Investments in securities (classified within other current or non-current assets) $
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-nuclear trust fund investments
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
39
$
3
$
17
$
47
43
82
14
99
334
5
1
744
39
68
8
1,523
674
6
680
$
$
$
$
$
$
45
42
—
—
—
334
—
1
191
—
—
—
616
257
—
257
$
$
$
2
1
82
14
99
—
5
—
509
39
—
—
768
358
6
364
$
$
$
19
—
—
—
—
—
—
—
—
44
—
—
—
63
59
—
59
The following tables reconcile, for the years ended December 31, 2018 and 2017, 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, 2018
Contracts acquired in XOOM acquisition
Total losses realized/unrealized included in earnings
Purchases
Transfers into Level 3 (b)
Transfers out of Level 3 (b)
Ending balance as of December 31, 2018
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, 2018
$
$
$
(a) Consists of derivatives assets and liabilities, net
For the Year Ended December 31, 2018
Fair Value Measurement Using Significant Unobservable
Inputs (Level 3)
Debt
Securities
Derivatives (a)
(In millions)
Total
19
—
—
—
—
—
19
$
$
(15) $
12
(21)
41
5
(2)
20
$
— $
(17) $
4
12
(21)
41
5
(2)
39
(17)
(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
135
Beginning balance as of January 1, 2017
Total gains realized/unrealized included in earnings
Purchases
Contracts reclassified to held-for-sale
Transfers into Level 3 (b)
Transfer 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
For the Year Ended December 31, 2017
Fair Value Measurement Using Significant Unobservable
Inputs (Level 3)
Debt
Securities
Derivatives (a)
(In millions)
Total
$
$
$
17
2
—
—
—
19
$
$
(64) $
37
(4)
4
(1)
13
(15) $
— $
1
$
(47)
39
(4)
4
(1)
13
4
1
(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
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.
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 10% of derivative assets
and 9% 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
136
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, 2018 and December 31, 2017 the credit reserve did
not result in a significant change in fair value.
The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2018, 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, 2018 and 2017:
Significant Unobservable Inputs
December 31, 2018
Fair Value
Input/Range
Power Contracts
FTRs
Assets
Liabilities
(In millions)
$
$
89
$
20
109
$
75
14
89
Valuation
Technique
Significant
Unobservable
Input
Low
High
Weighted
Average
Discounted
Cash Flow
Discounted
Cash Flow
Forward Market
Price (per MWh)
Auction Prices (per
MWh)
$
1
$
214
$
(90)
34
31
—
Significant Unobservable Inputs
December 31, 2017
Fair Value
Input/Range
Assets
Liabilities
(In millions)
Valuation
Technique
Significant
Unobservable
Input
Low
High
Weighted
Average
Power Contracts
FTRs
$
$
33
$
11
44
$
Discounted
Cash Flow
Discounted
Cash Flow
47
12
59
Forward Market
Price (per MWh)
Auction Prices (per
MWh)
$
10
$
142
$
(28)
46
24
—
137
The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable
inputs as of December 31, 2018 and 2017:
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, 2018, the Company recorded $287 million of cash collateral
posted and $33 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.
Counterparty Credit Risk
As of December 31, 2018, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, and registered
commodity exchanges and certain long-term agreements, was $301 million and NRG held collateral (cash and letters of credit)
against those positions of $123 million, resulting in a net exposure of $180 million. Approximately 66% of the Company's exposure
before collateral is expected to roll off by the end of 2020. 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
Utilities, energy merchants, marketers and other
Financial institutions
Total
Category
Non-Investment grade/Non-Rated
Investment grade
Total
Net Exposure (a) (b)
(% of Total)
89%
11
100%
Net Exposure (a) (b)
(% of Total)
51%
49
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 currently has no exposure to any individual wholesale counterparty in excess of 10% of the total net exposure
discussed above as of December 31, 2018. 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.
138
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 contracts, including
California tolling agreements 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, 2018, aggregate credit risk exposure managed by NRG to these counterparties was
approximately $434 million for the next five years. This amount excludes potential credit exposures for projects with long-term
PPAs that have not reached commercial operations and any exposure for entities classified as a discontinued operation.
NRG through its unconsolidated affiliates Ivanpah and Agua Caliente has exposure to PG&E of approximately $321 million
for the next five years. As a result of the bankruptcy filing by PG&E on January 29, 2019, it is uncertain whether and to what
extent the bankruptcy may have on these contracts. For further discussion see Note 15, Investments Accounted for by the Equity
Method and Variable Interest Entities.
Retail Customer Credit Risk
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, 2018, 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 $85 million, $68 million, and $45 million for the years ending
December 31, 2018, 2017, and 2016, 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 NPNS accounting. 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.
139
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 of a portion of anticipated power purchases for the Company's retail sales;
Fixing the price for a portion of anticipated future electricity sales that provides an acceptable return on the Company's
electric generation operations; and
Fixing the price of a portion of anticipated fuel purchases for the operation of the Company's power plants.
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, 2018, 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 2034;
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 2029.
Also, as of December 31, 2018, 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 2034;
•
Power tolling contracts through 2029;
• 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, 2018, NRG's derivative assets
consisted of interest rate derivative instruments on recourse debt extending through 2021.
140
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, 2018 and 2017. 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
Emissions
Renewables Energy Certificates Certificates
Coal
Natural Gas
Oil
Power
Capacity
Interest
Equity
Short Ton
MMBtu
Barrels
MWh
MW/Day
Dollars
Shares
Total Volume
December 31,
2018
December 31,
2017
(In millions)
(2)
1
13
(330)
1
1
(1)
1,000
—
$
1
—
21
(20)
—
23
(1)
1,060
1
$
The increase in the natural gas position was primarily the result of additional generation hedge positions.
Fair Value of Derivative Instruments
The following table summarizes the fair value within the derivative instrument valuation on the balance sheet:
(In millions)
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
Fair Value
Derivative Assets
Derivative Liabilities
December 31,
2018
December 31,
2017
December 31,
2018
December 31,
2017
$
$
$
17
22
747
295
8
31
616
128
$
— $
—
673
304
1,081
$
783
$
977
$
1
5
536
138
680
141
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, 2018
Commodity contracts:
Derivative assets
Derivative liabilities
Total commodity contracts
Interest rate contracts:
Derivative assets
Total interest rate contracts
Total derivative instruments
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
1,042
$
(977)
65
39
39
(In millions)
(778) $
778
—
—
—
104
$
— $
(31) $
114
83
—
—
83
$
Gross Amounts Not Offset in the Statement of Financial Position
Gross Amounts of
Recognized Assets/
Liabilities
Derivative
Instruments
Cash Collateral
(Held)/Posted
Net Amount
744
$
(674)
70
39
(6)
33
(In millions)
(578) $
578
—
—
—
—
(11) $
72
61
—
—
—
61
$
233
(85)
148
39
39
187
155
(24)
131
39
(6)
33
164
Total derivative instruments
$
103
$
— $
Accumulated Other Comprehensive Income
The following table summarizes the effects on NRG's accumulated OCI balance attributable to cash flow hedge derivatives,
net of tax:
Accumulated OCI beginning balance
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts
Mark-to-market of cash flow hedge accounting contracts
Sale of NRG Yield and Renewables
Accumulated OCI ending balance, net of $0, $8 and $16 tax
Interest Rate Contracts
2018
2017
2016
(In millions)
(54) $
(66) $
(101)
8
21
25
$
— $
12
—
— $
(54) $
21
14
—
(66)
$
$
$
Amounts reclassified from accumulated OCI into income are recorded in discontinued operations.
142
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 certain yield
interest rate swaps, while positively correlated, did not meet the required threshold for cash flow hedge accounting. As a result,
the Company de-designated these derivatives as cash flow hedges as of December 31, 2016, and prospectively marked these
derivatives to market through the income statement until the assets were sold.
The Company's regression analysis for certain Yield interest rate swaps, while positively correlated, no longer contain
matching terms for cash flow hedge accounting. As a result, the Company voluntarily de-designated these derivatives as cash
flow hedges as of April 28, 2017, and prospectively marked these derivatives to market through the income statement until the
assets were sold.
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 (gains)/losses on settled
positions related to economic hedges
Reversal of acquired gain positions related to economic hedges
Net unrealized gains 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
Net unrealized gains on open positions related to trading activity
Total unrealized mark-to-market gains/(losses) for trading activity
Total unrealized gains/(losses)
Unrealized (losses)/gains included in operating revenues
Unrealized gains/(losses) 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
2018
(In millions)
$
$
$
$
$
(73) $
(10)
$
47
—
97
14
(12)
29
17
31
$
159
206
(25)
14
(11)
195
$
Year Ended December 31,
2018
2017
(In millions)
2016
(113) $
144
31
$
— $
241
(46)
195
4
$
$
$
(128)
(12)
12
(128)
10
18
28
(100)
(608)
508
(100)
(8)
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, 2018, the $97 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, 2017, the $159 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 $12 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.
143
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,
2018 was $16 million. The collateral required for contracts with credit rating contingent features that are in a net liability position
as of December 31, 2018 was $14 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 $11 million as of
December 31, 2018.
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 for the securities held in the trust
funds, as well as information about the contractual maturities of those securities.
As of December 31, 2018
As of December 31, 2017
(In millions, except otherwise noted)
Fair
Value
Unrealized
Gains
Unrealized
Losses
Cash and cash equivalents
$
19
$
— $
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
46
100
22
96
376
4
1
1
—
1
231
—
$
663
$
234
$
—
—
2
1
2
1
—
6
Weighted-
average
maturities
(in years)
Fair
Value
Unrealized
Gains
Unrealized
Losses
Weighted-
average
maturities
(in years)
— $
47
$
— $
12
23
22
11
—
9
43
82
14
99
402
5
1
1
—
2
272
—
$
692
$
276
$
—
—
1
—
1
—
—
2
—
11
23
20
11
—
9
144
The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses
from these sales. The cost of securities sold is determined using the specific identification method.
Realized gains
Realized (losses)
Proceeds from sale of securities
Note 7 — Inventory
Inventory consisted of:
Fuel oil
Coal
Natural gas
Spare parts
Total Inventory
Year Ended December 31,
2018
2017
(In millions)
2016
$
$
17
(13)
513
$
22
(8)
501
26
(11)
510
As of December 31,
2018
2017
(In millions)
74
97
28
213
412
$
$
86
110
24
233
453
$
$
The Company recorded a lower of weighted average cost or market adjustment related to fuel oil for the years ended, December
21, 2018 and 2017 of $3 million and $33 million respectively.
Note 8 — Property, Plant and Equipment
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,
2018
2017
(In millions)
3,763
347
212
431
106
4,859
(1,811)
3,048
$
$
6,904
468
235
421
201
8,229
(2,255)
5,974
$
$
The Company recorded long-lived asset impairments during the years ended December 31, 2018 and 2017, as further
described in Note 9, Asset Impairments.
145
Note 9 — Asset Impairments
2018 Impairment Losses
Guam — During the fourth quarter of 2018, the Company concluded its wholly-owned subsidiary, NRG Solar Guam,
LLC, was held for sale after 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, 2018 based on the contractual sale price, which resulted in an
impairment loss of $12 million. On February 20, 2019, the Company completed the sale of Guam for cash consideration of
approximately $8 million.
Keystone and Conemaugh — On September 5, 2018, the Company sold its approximately 3.7% interests in the Keystone
and Conemaugh generating stations. NRG recorded impairment losses of $14 million for Keystone and $14 million for Conemaugh
to adjust the carrying amount of the assets to fair value based on the contractual sale price.
Dunkirk — During the second quarter of 2018, NRG ceased its development of the project to add gas capability at the Dunkirk
generating station. The project was put on hold in 2015 pending the resolution of a lawsuit filed by Entergy Corporation against
the NYPSC, which challenged the legality of its contract with Dunkirk. The lawsuit was later dropped and development continued,
but the delay imposed a new requirement on Dunkirk to enter into the NYISO interconnection study process. The NYISO studies
have concluded that extensive electric system upgrades would be necessary for the station to return to service. This would cause
the Company to incur a material increase in cost and delay the project schedule that would render the project impractical.
Consequently, the Company has recorded an impairment loss of $46 million, reducing the carrying amount of the related assets
to $0.
Other Impairments — As of December 31, 2018, the Company recorded additional asset impairment losses of approximately
$13 million and impairment losses on equity method investments of $15 million.
2017 Impairment Losses
South Texas Project — 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.
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 $0 during the second quarter of 2017. Subsequent
to the MIPA termination, BTEC filed claims against NRG Texas Power LLC with respect to the termination of the MIPA and NRG
filed counterclaims against BTEC as further described in Note 21, Commitments and Contingencies. On June 7, 2018, the parties
resolved all claims and counterclaims in the lawsuit.
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.
Other Impairments — During the year ended 2017, the Company recorded impairment losses of $29 million in connection
with renewable assets that were not divested as part of the sale of NRG Yield and the Renewables Platform. In addition, the
Company recorded an impairment loss of $20 million related to excess SO2 allowances and $10 million in impairment losses for
other investments.
146
2016 Impairment Losses
Rockford — As described in Note 3, Acquisitions, Discontinued Operations 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 their
fair market value.
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.
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 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 connection with the preparation of the annual budget, the Company noted that due to
the anticipated difficulty in refinancing Sherbino's debt, the project's fair value had decreased significantly below its carrying
amount and determined the impairment to be other-than-temporary. Accordingly, the Company determined that an impairment
existed and recorded an impairment loss on its investment in Sherbino of $70 million.
Other Impairments — During 2016, the Company recorded other impairment losses of $29 million in connection with
renewable assets that were not divested as part of the sale of NRG Yield and the Renewables Platform. In addition, the Company
also recorded impairment losses of $23 million in excess SO2 allowances, $19 million for other intangible assets, $19 million in
previously purchased solar panels and $22 million in other investments.
Note 10 — Goodwill and Other Intangibles
Goodwill
NRG's goodwill balance was $573 million and $539 million as of December 31, 2018 and 2017, respectively. The increase
in goodwill is due to the acquisition of XOOM. As of December 31, 2018 and 2017, NRG had approximately $366 million and $460
million, respectively, of goodwill that is deductible for U.S. income tax purposes in future periods. As of December 31, 2018, goodwill
consisted of $165 million associated with the acquisition of Midwest Generation and $408 million for Retail business acquisitions,
including Texas non-commodity and XOOM.
2017 Impairments of Goodwill
BETM — During the fourth quarter of 2017, the Company concluded that BETM was held for sale following 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 was included within non-current assets held-for-sale 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 Generation reporting unit, reducing the goodwill balance for Texas Generation to zero.
147
In connection with the annual impairment assessment, the Company performed step one of the two-step impairment test
for the Texas Generation 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 Generation 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 annual budget, 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 Generation 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 Generation 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, 2018, primarily reflect intangible assets established with the acquisitions
of various companies, including Texas Genco, Reliant Energy, Green Mountain Energy, Dominion, XOOM, Discount Power, Energy
Alternatives, Energy Plus, Energy Systems, Energy Curtailment Specialists, Pioneer Energy, Stat Energy and Source Power & Gas.
Intangible assets are comprised of the following:
• Energy supply contracts — 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.
• Customer contracts — 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. The customer relationships are amortized to depreciation and amortization expense based on the expected discounted
future net cash flows by year.
• Marketing partnerships — 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 — These intangibles are amortized to depreciation and amortization expense on a straight-line basis.
•
• 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, 2018,
the Company recorded an impairment loss of $5 million to reduce the value of excess SO2 allowances to zero.
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.
•
• Other — Consists of renewable energy credits and costs to extend the operating license for STP Units 1 and 2.
148
The following tables summarize the components of NRG's intangible assets subject to amortization:
Year Ended December 31, 2018
Emission
Allowances
Fuel
Customer
Contracts
Customer
Relationships
Marketing
Partnerships
Trade
Names
Other
Total
Contracts
$
January 1, 2018
Purchases
Acquisition of businesses(a)
Usage
Write-off of fully amortized
balances
Impairment
Other
December 31, 2018
Less accumulated
amortization
$
755
33
—
(1)
(107)
(5)
(16)
659
$
49
—
—
—
—
—
—
49
$
1
—
—
—
—
—
—
1
(515)
(45)
(1)
Net carrying amount
$
144
$
4
$ — $
$
768
—
122
—
(411)
(1)
—
478
$
88
—
43
—
—
—
—
131
$
342
—
13
—
(10)
—
—
345
$
77
28
—
(26)
—
—
—
79
2,080
61
178
(27)
(528)
(6)
(16)
1,742
(314)
164
$
(61)
70
$
(195)
150
$
(20)
59
$
(1,151)
591
(a) The weighted average life of acquired intangibles is: customer relationships 6 years, trade names 7 years, and marketing partnerships 14 years
Year Ended December 31, 2017
Emission
Allowances
Energy
Supply
Fuel
Customer
Contracts
Customer
Relationships
Marketing
Partnerships
Trade
Names
Other
Total
Contracts
$
342
$ 75
$
2,162
January 1, 2017
Purchases
Acquisition of businesses
Usage
Write-off of fully amortized
balances
Impairment
Other
December 31, 2017
Less accumulated
amortization
$
780
$
54
$72
$
27
—
(10)
—
(20)
(22)
755
— —
— —
— —
(54)
(23)
— —
— —
— 49
1
—
—
—
—
—
—
1
(583)
— (45)
(1)
Net carrying amount
$
172
$ — $ 4
$ — $
(In millions)
$
750
$
—
18
—
—
—
—
768
88
—
—
—
—
—
—
88
—
32
—
—
— (28)
—
—
—
342
—
—
(2)
77
(693)
75
$
(54)
34
$
(182)
160
(15)
$ 62
$
59
18
(38)
(77)
(20)
(24)
2,080
(1,573)
507
The following table presents NRG's amortization of intangible assets for each of the past three years:
Years Ended December 31,
Amortization
Emission allowances
Energy supply contracts
Fuel contracts
Customer relationships
Marketing partnerships
Trade names
Other
Total amortization
2018
$
39
—
—
32
9
23
4
2017
(In millions)
$
71
$
2016
1
1
34
5
23
3
62
6
1
48
8
23
9
$
107
$
138
$
157
149
The following table presents estimated amortization of NRG's intangible assets for each of the next five years:
Year Ended December 31,
Emission
Allowances
Fuel
Contracts
Customer
Relationships
Marketing
Partnerships
Trade
Names
Other
Total
2019
2020
2021
2022
2023
(In millions)
$
$
48
37
43
50
49
$
— $
1
—
—
1
38
39
33
23
26
$
11
11
10
10
10
$
24
25
24
24
24
$
3
3
3
3
3
124
116
113
110
113
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,
2018 and 2017, the value of emission allowances held-for-sale is $12 million and $9 million, respectively, 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 $121 million
acquired in the acquisition of Midwest Generation. These out-of-market contracts are amortized to cost of operations. As of
December 31, 2018 and 2017, the Company had accumulated amortization for out-of-market contracts of $37 million and $29 million,
respectively. Upon adoption of ASC 842, Leases, on January 1, 2019, out-of-market lease contracts are included as a component of
right-of-use assets.
The following table summarizes the estimated amortization related to NRG's out-of-market contracts:
Year Ended December 31,
2019
2020
2021
2022
2023
Leases
$
8
8
8
8
8
150
Note 11 — Debt and Capital Leases
Long-term debt and capital leases consisted of the following:
(In millions, except rates)
Recourse debt:
Senior Notes, due 2022
Senior Notes, due 2024
Senior Notes, due 2026
Senior Notes, due 2027
Senior Notes, due 2028
Convertible Senior Notes, due 2048
Term loan facility, due 2023
Tax-exempt bonds
Subtotal recourse debt
Non-recourse debt:
Ivanpah, due 2033 and 2038(b)
Agua Caliente, due 2037(c)
Agua Caliente Borrower 1, due 2038
Midwest Generation, due 2019
Other (d)
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
(a) As of December 31, 2018, L+ equals 1-month LIBOR plus 1.75%
(b) The Company deconsolidated Ivanpah during the second quarter of 2018
(c) The Company deconsolidated Agua Caliente solar facility during the third quarter of 2018
(d) Guam was reclassified to held for sale during the fourth quarter of 2018
Debt includes the following discounts:
Term loan facility, due 2023
Midwest Generation, due 2019
Convertible Senior Notes, due 2048
Total discounts
Consolidated Annual Maturities
December 31,
2018
December 31,
2017
December 31, 2018
interest rate %(a)
6.250
6.250
7.250
6.625
5.750
2.750
L+1.75
4.125 - 6.00
2.285 - 4.256
2.395 - 3.633
5.430
4.390
various
various
$
$
— $
733
1,000
1,230
821
575
1,698
466
6,523
—
—
86
48
34
168
6,691
1
6,692
(72)
(70)
(101)
6,449
$
992
733
1,000
1,250
870
—
1,872
465
7,182
1,073
818
89
152
180
2,312
9,494
5
9,499
(204)
(103)
(12)
9,180
As of December 31,
2018
2017
(In millions)
(4) $
(1)
(96)
(101) $
(7)
(5)
—
(12)
$
$
As of December 31, 2018, annual payments based on the maturities of NRG's debt and capital leases are expected to be as
follows:
2019
2020
2021
2022
2023
Thereafter
Total
(In millions)
74
26
27
25
1,635
4,905
6,692
$
$
151
Recourse Debt
Issuance of 2048 Convertible Senior Notes
During the second quarter of 2018, NRG issued $575 million in aggregate principal amount of 2.75% Convertible Senior
Notes due 2048, or the Convertible Notes. The Convertible Notes are convertible, under certain circumstances, into the Company's
common stock, cash or a combination thereof (at NRG's option) at an initial conversion price of $47.74 per common share, which
is equivalent to an initial conversion rate of approximately 20.9479 shares of common stock per $1,000 principal amount of
Convertible Notes. Interest on the Convertible Notes is payable semi-annually in arrears on June 1 and December 1 of each year,
commencing on December 1, 2018. The Convertible Notes mature on June 1, 2048, unless earlier repurchased, redeemed or
converted in accordance with their terms. The Convertible Notes are guaranteed by certain NRG subsidiaries. Prior to the close
of business on the business day immediately preceding December 1, 2024, the Convertible Notes will be convertible only upon
the occurrence of certain events and during certain periods, and thereafter during specified periods as follows:
•
from December 1, 2024 until the close of business on the second scheduled trading day immediately before
June 1, 2025; and
•
from December 1, 2047 until the close of business on the second scheduled trading day immediately before
the maturity date.
The Convertible Notes are accounted for in accordance with ASC 470-20, Debt with Conversion and Other Options. Under
ASC 470-20, issuers of convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement,
are required to separately account for the liability (debt) and equity (conversion option) components. The carrying amount of the
liability component at issuance date of $472 million was calculated by estimating the fair value of similar liabilities without a
conversion feature. The residual principal amount of the notes of $103 million was allocated to the equity component with offset
to debt discount. The debt discount will be amortized to interest expense using the effective interest method over seven years
which is determined to be the expected life of the Convertible Notes.
The Company incurred approximately $12 million in transaction costs in connection with the issuance of the notes. These
costs were allocated to the liability and equity components in proportion to the allocation of proceeds. Transaction costs of $10
million, allocated to the liability component, were recognized as deferred financing costs and are amortized over the seven years.
Transaction costs of $2 million, allocated to the equity component, were recognized as a reduction of additional paid-in capital.
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.
2018 Senior Note Repurchases
During the year ended December 31, 2018 the Company completed senior note repurchases, as detailed in the table below.
In addition, during the year ended December 31, 2018, a $38 million loss on debt extinguishment was recorded for these
repurchases, which included the write-off of previously deferred financing costs of $7 million.
In millions, except percentages
5.750% senior notes due 2028
6.250% senior notes due 2022
Total at June 30, 2018
6.250% senior notes due 2022
5.750% senior notes due 2028
6.625% senior notes due 2027
Total at September 30, 2018
6.250% senior notes due 2022
Total at December 31, 2018
(a) Includes accrued interest of $14 million
Principal
Repurchased
Cash Paid (a)
Average Early Redemption
Percentage
$
$
$
$
29
14
43
493
20
20
576
485
1,061
$
$
$
$
30
15
45
512
20
21
598
508
1,106
99.24%
103.25%
103.13%
99.13%
103.06%
103.13%
152
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. 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 percentages
7.625% senior notes due 2018
7.875% senior notes due 2021
6.625% senior notes due 2023
Total
(a) Includes accrued interest of $29 million
Senior Notes Early Redemption
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%
As of December 31, 2018, NRG had the following outstanding issuances of senior notes with an early redemption feature,
or Senior Notes:
i.
ii.
iii.
iv.
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.
The Company periodically enters into supplemental indentures for the purpose of adding entities under the 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.
2024 Senior Notes
At any time prior to May 1, 2019, NRG may redeem up to 35% of the aggregate principal amount 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
153
Redemption
Percentage
103.125%
102.083%
101.042%
100.000%
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:
154
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 the previous 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 term 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. 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%. On March 21, 2018, NRG again repriced the 2023 Term Loan Facility, reducing the interest
rate margin by 50 basis points to LIBOR plus 1.75% and reducing the LIBOR floor to 0.00%.
• 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 both pay interest at a rate of LIBOR plus 2.25%. On May 7, 2018, NRG entered into the third amendment
agreement extending the maturity date of the Tranche A revolving facility to June 30, 2021, for the Tranche A accepting
lender.
In accordance with the terms of the Credit Agreement, on October 5, 2018, the Company initiated an asset sale offer to
purchase a portion of its Term Loan following the sale of NRG Yield and the Renewables Platform. The offer expired on November
5, 2018 and $260 million of Term Loan holders accepted the offer. As a result, the Company prepaid $155 million of Term Loans
as part of its de-leveraging plan, as well as established an incremental first lien secured term loan facility under the Senior Credit
Facility in the aggregate principal amount of $105 million on the same terms and conditions to stay within its debt reduction
target. In addition, a $3 million loss on debt extinguishment was recorded, which included the write-off of previously deferred
financing costs of $2 million.
In accordance with the terms of the credit agreement, upon the consummation of the sales of the South Central Portfolio
and Carlsbad, the Company will initiate asset sale offers to purchase a portion of its Term Loan. The Company has one year from
the dates of each sale to initiate the offer.
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,
2018
2017
Interest Rate %
$
$
$
57
190
59
33
54
73
466
$
57
190
59
32
54
73
465
6.000
5.375
5.875
4.125
4.750
4.750
155
Non-Recourse Debt
The following are descriptions of certain indebtedness of NRG's subsidiaries that are outstanding as of December 31, 2018.
All of NRG's non-recourse debt is secured by the assets in the respective project subsidiaries as further described below.
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, 2018, $48 million was outstanding.
Agua Caliente Borrower I
On January 22, 2019, the lenders of the Agua Borrower I debt notified the Company of certain defaults under the financing
agreement as it relates to the bankruptcy filing made by PG&E on January 29, 2019. PG&E is the offtaker of the underlying
contracts, which are material. The financing was entered into along with Agua Caliente Borrower 2, LLC, a subsidiary of Clearway
Energy Inc., which is joint and several to the parties. The Company is working with the lenders to determine a path forward.
Note 12 — Asset Retirement Obligations
The Company's AROs are primarily related to the environmental obligations related to nuclear decommissioning, ash
disposal, site closures, and fuel storage facilities and future dismantlement of equipment on leased property. 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 treatment per ASC 980,
Regulated Operations. Nuclear decommissioning ARO liabilities were $282 million and $269 million as of December 31, 2018
and 2017, respectively.
The following table represents the balance of ARO obligations as of December 31, 2018 and 2017, along with the additions,
reductions and accretion related to the Company's ARO obligations for the year ended December 31, 2018:
Balance as of December 31, 2017
Revisions in estimates for current obligations
Additions
Spending for current obligations
Accretion — Expense
Accretion — Nuclear decommissioning
Balance as of December 31, 2018
(In millions)
679
(27)
9
(27)
30
15
679
$
$
Note 13 — 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.
156
NRG maintains two separate qualified pension plans, the NRG Pension Plan for Bargained Employees and the NRG Pension
Plan. Employees of NRG participate in each of the pension plans, depending upon whether their employment is covered by a
bargaining agreement.
NRG and GenOn entered into a Restructuring Support Agreement in which NRG agreed to retain GenOn's pension liability
for service provided by GenOn employees prior to the completion of the GenOn reorganization. NRG determined that the retention
of this liability was probable and recorded the estimated accumulated pension benefit obligation as of December 31, 2017 of $92
million, which reflects a $13 million contribution made by NRG to the plan in 2017, in other non-current liabilities with a
corresponding loss from discontinued operations. NRG also agreed to retain the liability for GenOn's post-employment and retiree
health and welfare benefits with the obligation capped at $25 million. NRG's obligation for both of these liabilities was revalued
at GenOn's emergence from bankruptcy.
NRG expects to contribute $41 million to the Company's pension plans in 2019, of which $13 million relates to GenOn.
NRG Defined Benefit Plans
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
Settlement/curtailment expense
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
Year Ended December 31,
Pension Benefits
2018
2017
(In millions)
2016
23
44
(62)
—
7
12
$
$
26
43
(58)
4
—
15
$
$
Year Ended December 31,
Other Postretirement Benefits
2018
2017
(In millions)
2016
$
1
4
(10)
—
(10)
(15) $
$
1
4
(9)
(1)
—
(5) $
30
43
(60)
2
—
15
2
6
(5)
—
—
3
$
$
$
$
157
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:
Benefit obligation at January 1
Service cost
Interest cost
Plan amendments
Actuarial (gain)/loss
Employee and retiree contributions
Curtailment gain
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
As of December 31,
Pension Benefits
Other Postretirement
Benefits
2018
2017
2018
2017
(In millions)
$
$
$
$
1,329
23
44
17
(95)
—
(20)
(76)
1,222
1,104
(80)
—
33
(76)
981
$
1,241
26
43
—
77
—
—
(58)
1,329
953
173
—
36
(58)
1,104
$
128
1
4
(28)
(6)
3
(7)
(12)
83
—
—
3
9
(12)
—
(241) $
—
—
(241) $
(225) $
—
—
(225) $
(83) $
—
—
(83) $
128
1
4
(1)
6
3
—
(13)
128
—
—
3
10
(13)
—
(128)
38
(25)
(115)
(a) NRG's liability for GenOn's other postretirement benefit plans was capped at $25 million, with the final liability assumed determined as of GenOn's
emergence from bankruptcy. As of December 31, 2017, the liability was $38 million so NRG's obligation was recorded at the $25 million cap. Upon
emergence, the retained liability was $23 million, therefore NRG is obligated for the full retained liability of the plans.
Amounts recognized in NRG's balance sheets were as follows:
Current liabilities
Less: GenOn other postretirement benefits
Total current liabilities
Non-current liabilities
Less: GenOn other postretirement benefits
Total non-current liabilities
As of December 31,
Pension Benefits
Other Postretirement
Benefits
2018
2017
2018
2017
$
$
$
$
— $
—
— $
241
—
241
$
$
(In millions)
— $
—
— $
225
—
225
$
$
7
—
7
76
—
76
$
$
$
$
7
(3)
4
121
(10)
111
158
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
2018
2017
2018
2017
$
$
$
90
3
93
—
93
$
$
$
(In millions)
53
3
56
(22)
34
$
$
$
(9) $
(53)
(62) $
—
(62) $
Other changes in plan assets and benefit obligations recognized in OCI were as follows:
Year Ended December 31,
Pension
Benefits
Other Postretirement
Benefits
2018
2017
2018
2017
Net actuarial loss/(gain)
Amortization of net actuarial (gain)/loss
Curtailment
Prior service credit
Amortization of prior service cost
Total recognized in OCI
Less: GenOn (deconsolidated June 14, 2017)
Net recognized in OCI
Less: GenOn post deconsolidation net periodic benefit
cost
Net periodic benefit cost/(credit)
Net recognized in net periodic pension cost/(credit) and
OCI
$
$
$
$
$
$
$
47
—
(27)
17
—
37
—
37
—
12
(In millions)
(37) $
(4)
—
—
—
(41) $
$
15
(26) $
—
15
(5) $
—
2
(28)
10
(21) $
— $
(21) $
—
(15)
49
$
(11) $
(36) $
(4)
(37)
(41)
10
(31)
6
1
—
(1)
9
15
2
17
1
(5)
13
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.
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 $4 million and $0 million, respectively. 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 $13 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
2018
2017
$
(In millions)
$
1,222
1,188
981
1,329
1,255
1,104
159
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
Common/collective trust investment — non-core assets
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 — 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
Fair Value Measurements as of December 31, 2018
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
Significant
Observable Inputs
(Level 2)
(In millions)
Total
$
$
— $
—
—
—
12
12
$
183
53
117
256
—
609
$
$
$
183
53
117
256
12
621
70
249
16
25
981
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
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
2018
2017
2018
2017
3.71%
3.00%
—
4.37%
—%
7.8% grading to
4.5% in 2025
3.71%
—
8.2% grading to
4.5% in 2025
4.38%
3.00%
—
160
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
2018
3.71%/4.04%
2017
2016
2018
2017
2016
4.26%
4.52%
3.71%/4.08%
4.29%
4.55%
6.17%
6.85%
6.65%
3.00%
3.00%
3.00%
—
—
—
—
—
—
Health care trend rate
—
—
8.2% grading to
4.5% in 2025
7.0% grading to
5.0% in 2025
7.25% grading
to 5.0% in 2025
—
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 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.
The target allocations of NRG's pension plan assets were as follows for the year ended December 31, 2018:
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.
161
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:
Asset Class
Index
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
(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,
are as follows:
2019
2020
2021
2022
2023
2024-2028
Other Postretirement Benefit
Pension
Benefit Payments
Benefit Payments
(In millions)
Medicare Prescription
Drug Reimbursements
$
$
72
76
79
82
85
418
$
7
7
7
6
6
26
—
—
—
—
—
1
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The impact
of a one-percentage-point change in assumed health care cost trend rates is immaterial on total service and interest costs components
but would have the following effect:
Effect on postretirement benefit obligation
STP Defined Benefit Plans
1-Percentage-
Point Increase
1-Percentage-
Point Decrease
(In millions)
5
(4)
NRG has a 44% undivided ownership interest in STP, as discussed further in Note 26, 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 years ended December 31, 2018 and December 31, 2017, NRG reimbursed STPNOC $13
million and $8 million, respectively, for its contribution to the plans. In 2019, NRG expects to reimburse STPNOC $18 million
for its contribution to the plans.
The Company has recognized the following in its statement of financial position, statement of operations and accumulated
OCI related to its 44% interest in STP:
As of December 31,
Pension Benefits
Other Postretirement Benefits
2018
2017
2018
2017
Funded status — STPNOC benefit plans
Net periodic benefit cost/(credit)
Other changes in plan assets and benefit obligations
recognized in other comprehensive (loss)/income
$
(78) $
8
(7)
(In millions)
(76) $
8
(6)
(19) $
(7)
2
(24)
(3)
5
162
Defined Contribution Plans
NRG's employees are also eligible to participate in defined contribution 401(k) plans.
The Company's contributions to these plans were as follows:
Company contributions to defined contribution plans
$
28
$
56
$
55
Year Ended December 31,
2018
2017
(In millions)
2016
Note 14 — Capital Structure
For the period from December 31, 2015 to December 31, 2018, 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:
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
Shares issued under ESPP
Shares issued under LTIPs
Share repurchases
Balance as of December 31, 2018
Common Stock
Issued
416,939,950
—
643,875
417,583,825
—
739,309
418,323,134
—
1,965,752
—
420,288,886
Common
Treasury
(102,749,908)
609,094
—
(102,140,814)
560,769
—
(101,580,045)
175,862
—
(35,234,664)
(136,638,847)
Outstanding
314,190,042
609,094
643,875
315,443,011
560,769
739,309
316,743,089
175,862
1,965,752
(35,234,664)
283,650,039
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, 2018:
Equity Instrument
Long-term incentive plans
Common Stock
Reserve Balance
17,631,031
Common stock dividends — In the first quarter of 2016 the Company paid quarterly dividend 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. The Company paid $0.030 dividend per common share for the second quarter
of 2016 through the fourth quarter of 2018.
On January 23, 2019, 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, 2019, to stockholders of record as of February 1, 2019
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. Beginning January 2018, NRG suspended the ESPP. As of December 31, 2018, there remained 2,931,188
shares of treasury stock reserved for issuance under the ESPP.
163
Share Repurchases — In 2018, the Company's board of directors authorized the Company to repurchase $1.5 billion of its
common stock. In addition, the Company's board of directors authorized in February 2019 an additional $1.0 billion share repurchase
program to be executed in 2019.
The following table summarizes the shares repurchased under the 2018 program, including shares repurchased under two
completed accelerated repurchase agreements:
Open market repurchases
Shares repurchased under May 24, 2018 Accelerated Repurchase Agreement
Total number
of shares
purchased
11,097,631
10,829,903
Average price
paid per share
Amounts paid
for shares
purchased (in
millions)
$
Shares repurchased under September 5, 2018 Accelerated Repurchase Agreement
13,307,130
Total Share Repurchases as of December 31, 2018
Additional open market repurchases through February 28, 2019
35,234,664
6,153,415
Total Share Repurchases as of February 28, 2019
41,388,079 $
36.24 $
396
354
500
1,250
250
1,500
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
$345 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 was reflected in net loss available to NRG common
stockholders in the calculation of earnings per share for the year ended December 31, 2016.
The following table reflects the changes in the Company's redeemable preferred stock balance for the years ended
December 31, 2018, 2017, and 2016:
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
Balance as of December 31, 2018
(In millions)
$
$
$
$
302
2
(226)
(78)
—
—
—
164
Note 15 — 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 a number of elements including impairments, unrealized gains and losses on derivatives
and movements in foreign currency exchange rates.
The following table summarizes NRG's equity method investments as of December 31, 2018:
Name
Agua Caliente
Gladstone
Ivanpah Master Holdings, LLC
Watson Cogeneration Company
Midway-Sunset Cogeneration Company
Other(a)
Total equity investments in affiliates
(a) Refer to Note 9, Asset Impairments, for discussion of NRG's investment in Petra Nova Parish Holdings, LLC
Undistributed earnings from equity investments
Economic
Interest
Investment
Balance
(In millions)
35.0%
37.5%
54.5%
49.0%
50.0%
Various
$
200
140
37
17
12
6
412
As of December 31,
2018
2017
$
(In millions)
34
$
38
PG&E Bankruptcy - The Company's Agua Caliente and Ivanpah projects are party to PPAs with PG&E. Both projects have
project financing with the U.S. DOE. On January 29, 2019, PG&E Corp. and subsidiary utility PG&E filed for Chapter 11 bankruptcy
protection. As part of their filing, PG&E asked the Bankruptcy Court to confirm "exclusive jurisdiction" over their "rights to reject"
PPAs or other contracts regulated by FERC. As a result of the bankruptcy filing, the Agua Caliente and Ivanpah projects have issued
notices of events of default under their respective loan agreements. The Company is working with its partners on the projects and
the loan counterparties, however, given the uncertainty involved in bankruptcy proceedings, it is uncertain whether, and to what
extent, PG&E's bankruptcy may in the future impact the PPAs and have any resulting impact on the Agua Caliente and Ivanpah
projects. NRG's maximum exposure to loss is limited to its equity investment, which was $200 million for Agua Caliente and $37
million for Ivanpah. See Note 11, Debt and Capital Leases for further discussion on Agua Caliente.
Variable Interest Entities
NRG accounts for its interests in certain entities that are considered VIEs under ASC 810, Consolidation, for which NRG is
not the primary beneficiary, under the equity method.
Through its consolidated subsidiary, NRG Solar Ivanpah LLC, NRG owns a 54.5% interest in Ivanpah Master Holdings,
LLC, or Ivanpah, the owner of three solar electric generating projects located in the Mojave Desert with a total capacity of 393
MW. NRG considers this investment a VIE under ASC 810 and NRG is not considered the primary beneficiary. The Company
accounts for its interest under the equity method of accounting.
The Ivanpah solar electric generating projects were funded in large part by loans guaranteed by the U.S. DOE and equity
from the projects' partners. During the first quarter of 2018, all interested parties sought a restructuring of Ivanpah's debt in order
to avoid a potential event of default with respect to the loans in connection with several recent events. Ensuing negotiations
culminated in a settlement during the second quarter of 2018 between the parties which resulted in certain transactions, including
the release of reserves totaling $95 million to fund equity distributions to the partners, which reduced the equity at risk, and the
prepayment of certain of the debt balance outstanding, and the amendment of certain of Ivanpah's governing documents. The equity
distributions and prepayment of debt were funded by the agreed upon release of reserve funds. These events were considered to
be a reconsideration event in accordance with ASC 810. As a result, NRG determined that it is not the primary beneficiary and
deconsolidated Ivanpah. NRG recognized a loss of $22 million on the deconsolidation and subsequent recognition of Ivanpah as
an equity method investment. The deconsolidation of Ivanpah reduced the Company's assets by approximately $1.3 billion, which
was primarily property, plant and equipment, and reduced the Company's liabilities by $1.2 billion, which was primarily long-term
debt.
165
Other Equity Investments
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 $140 million as of December 31,
2018.
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 eligible for certain tax credits as further described in Note 2, Summary of Significant
Accounting Policies.
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
Net assets less noncontrolling interests
Note 16 — Earnings/(Loss) Per Share
December 31, 2018
3
$
December 31, 2017
6
$
76
28
107
2
29
7
38
19
50
$
80
36
122
3
30
7
40
19
63
$
Basic income/(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 income/(loss) per share is computed in a manner
consistent with that of basic income/(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 income/(loss)
per share. However, these instruments are included in the denominator for purposes of computing diluted income/(loss) per share
under the treasury stock method. The if-converted method was used to determine the dilutive effect of the 2048 Convertible Senior
Notes for the year ended December 31, 2018. During 2016, the Company repurchased 100% of the outstanding shares of its 2.822%
% preferred stock.
166
The reconciliation of NRG's basic income/(loss) per share to diluted income/(loss) per share is shown in the following table:
Basic income/(loss) per share attributable to NRG common stockholders
Net income/(loss) attributable to NRG Energy, Inc.
Dividends for preferred shares
Gain on redemption of 2.822% redeemable perpetual preferred shares
Income/(Loss) Available to Common Stockholders
Weighted average number of common shares outstanding-basic
Income/(Loss) per weighted average common share — basic
Diluted income/(loss) per share attributable to NRG common stockholders
Weighted average number of common shares outstanding-basic
Incremental shares attributable to the issuance of equity compensation (treasury stock
method)
Total dilutive shares
Income/(Loss) per weighted average common share — diluted
Year Ended December 31,
2018
2017
2016
(In millions, except per share amounts)
$
$
$
268
$
(2,153) $
—
—
268
304
—
—
$
(2,153) $
317
0.88
$
(6.79) $
304
4
308
317
—
317
(774)
5
(78)
(701)
316
(2.22)
316
—
316
$
0.87
$
(6.79) $
(2.22)
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 income/(loss) per share:
Equity compensation plans
2048 Convertible Senior Notes
Total
Note 17 — Segment Reporting
Year Ended December 31,
2018
2017
2016
(In millions of shares)
—
7
7
5
—
5
5
—
5
The Company's segment structure reflects how management currently makes financial decisions and allocates resources.
The Company's businesses are segregated into the Generation, Retail and corporate segments. Generation includes all power
plant activities, domestic and international, as well as renewables. Retail includes Mass customers and Business Solutions, which
includes C&I customers and other distributed and reliability products. Intersegment sales are accounted for at market.
As described in Note 3, Acquisitions, Discontinued Operations and Dispositions, the Company has determined that the
South Central Portfolio, NRG Yield Inc. and its Renewables Platform, Carlsbad, and GenOn all qualified for treatment as
discontinued operations. The financial information for all historical periods has been recast to reflect the presentation of
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 year ended December 31, 2018, the Company had one customer in the Generation segment that comprised
11% of the Company's consolidated revenues. During the years ended December 31, 2017 and 2016, the Company had no
customer that comprised more than 10% of the Company's consolidated revenues.
167
Operating revenues(a)
Operating expenses
Depreciation and amortization
Impairment losses
Development costs
Total operating cost and expenses
Gain on sale of assets
Operating income/(loss)
Equity in earnings of unconsolidated affiliates
Impairment losses on investments
Other income/(expenses), net
Loss on debt extinguishment
Interest expense
Income/(loss) from continuing operations before income taxes
Income tax expense
Net income/(loss) from continuing operations
Loss from discontinued operations, net of income tax
Net Income/(loss)
Less: Net income/(loss) attributable to noncontrolling interests and
redeemable noncontrolling interests
Net income/(loss) attributable to NRG Energy, Inc.
Balance sheet
Equity investments in affiliates
Capital expenditures
Goodwill
Total assets
(a) Inter-segment sales and inter-segment net derivative gains and
losses included in operating revenues
$
$
$
$
$
9,478
7,997
421
99
11
8,528
32
982
9
(15)
18
(44)
(483)
467
7
460
(192)
268
—
268
412
388
573
For the Year Ended December 31, 2018
Corporate(a)
(In millions)
11
$
Eliminations
Total
$
(1,068) $
Retail (a)
Generation(a)
$
7,103
5,919
116
1
1
6,037
—
1,066
—
—
—
—
(3)
1,063
1
1,062
—
1,062
1
3,432
3,019
272
98
9
3,398
2
36
10
(15)
20
—
(58)
(7)
—
(7)
—
(7)
9
125
33
—
2
160
30
(119)
4
—
(1)
(44)
(422)
(582)
6
(588)
(192)
(780)
(5)
(1,066)
—
—
(1)
(1,067)
—
(1)
(5)
—
(1)
—
—
(7)
—
(7)
—
(7)
(5)
1,061
$
(16) $
(775) $
(2) $
— $
90
408
412
267
165
$
— $
— $
31
—
—
—
3,291
$
5,735
$
7,003
$
(5,401) $
10,628
9
$
1,085
$
(26) $
— $
1,068
168
Operating revenues(a)
Operating expenses
Depreciation and amortization
Impairment losses
Development costs
Total operating cost and expenses
Other income - affiliate
Gain on sale of assets
Operating income/(loss)
Equity in (losses)/earnings of unconsolidated affiliates
Impairment losses on investments
Other income, net
Loss on debt extinguishment
Interest expense
Income/(loss) from continuing operations before income taxes
Income tax (benefit)/expense
Net income/(loss) from continuing operations
Loss from discontinued operations, net of income tax
Net Income/(loss)
Less: Net income/(loss) attributable to noncontrolling interests and
redeemable noncontrolling interests
Net income/(loss) attributable to NRG Energy, Inc.
Balance sheet
Equity investments in affiliates
Capital expenditures
Goodwill
Total assets
(a) Inter-segment sales and inter-segment net derivative gains and
losses included in operating revenues
$
$
$
$
For the Year Ended December 31, 2017
Retail (a)
Generation(a)
Eliminations
Total
$
6,369
$
Corporate(a)
(In millions)
$
13
243
35
—
6
284
87
1
(183)
5
(4)
28
(49)
(451)
(654)
(38)
(616)
(992)
(1,608)
(189)
3,615
3,071
454
1,526
13
5,064
—
15
(1,434)
(14)
(75)
23
—
(100)
(1,600)
2
(1,602)
—
(1,602)
4
$
(923) $
(925)
(3)
—
—
(928)
—
—
5
(5)
—
—
—
—
—
—
—
—
—
—
5,377
110
8
3
5,498
—
—
871
—
—
—
—
(6)
865
(8)
873
—
873
1
9,074
7,766
596
1,534
22
9,918
87
16
(741)
(14)
(79)
51
(49)
(557)
(1,389)
(44)
(1,345)
(992)
(2,337)
(184)
(2,153)
182
250
539
872
$
(1,606) $
(1,419) $
— $
— $
82
374
$
179
148
165
95
20
—
$
(92) $
—
—
2,655
$
9,090
$
17,402
$
(5,792) $
23,355
4
$
877
$
42
$
— $
923
169
For the Year Ended December 31, 2016
Retail
Generation(a)
Eliminations
Total
Operating revenues(a)
Operating expenses
Depreciation and amortization
Impairment losses
Development costs
Total operating costs and expenses
Other income - affiliate
Loss on sale of assets
Operating income/(loss)
Equity in (losses)/earnings of unconsolidated affiliates
Impairment losses on investments
Other (expense)/income, net
Loss on debt extinguishment
Interest expense
Income/(loss) from continuing operations before income taxes
Income tax expense/(benefit)
$
6,330
$
5,162
114
1
4
5,281
—
(1)
1,048
—
—
(6)
—
6
1,048
1
Net income/(loss) from continuing operations
$
1,047
$
Income from discontinued operations, net of income tax
Net Income/(loss)
Less: Net loss attributable to noncontrolling interests and
redeemable noncontrolling interests
Net income/(loss) attributable to NRG Energy, Inc.
(a) Inter-segment sales and inter-segment net derivative gains and
losses included in operating revenues
$
$
—
1,047
—
Corporate(a)
(In millions)
$
74
353
52
30
29
464
193
(79)
(276)
45
(20)
33
(142)
(495)
(855)
25
(880)
65
(815)
(104)
3,633
3,322
593
452
15
4,382
—
—
(749)
(63)
(248)
22
—
(96)
(1,134)
(1)
(1,133)
—
(1,133)
(1)
$
(1,122) $
(1,129)
(3)
—
—
(1,132)
—
—
10
—
—
(2)
—
2
10
—
10
—
10
(12)
8,915
7,708
756
483
48
8,995
193
(80)
33
(18)
(268)
47
(142)
(583)
(931)
25
(956)
65
(891)
(117)
(774)
1,047
$
(1,132) $
(711) $
22
$
16
$
999
$
107
$
— $
1,122
Note 18 — Income Taxes
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/(benefit)
Effective income tax rate
Year Ended December 31,
2018
2017
2016
(In millions, except percentages)
$
$
$
6
6
(16)
16
1
1
7
1.5%
$
$
19
19
(60)
(5)
2
(63)
(44)
3.2%
$
6
6
23
(6)
2
19
25
(2.7)%
170
The following represents the domestic and foreign components of income/(loss) from continuing operations before income
taxes:
U.S.
Foreign
Total
Year Ended December 31,
2018
2017
(In millions)
2016
$
$
468
(1)
467
$
$
(1,406) $
17
(1,389) $
(942)
11
(931)
A reconciliation of the U.S. federal statutory tax rate to NRG's effective tax rate is as follows:
Income/(loss) from continuing operations before income taxes
Tax at federal statutory tax rate
State taxes
Foreign operations
Permanent differences
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 ("PTC")
Recognition of uncertain tax benefits
State rate change including true-up to current period activity
Alternative minimum tax ("AMT") refundable credit
Other
Income tax expense/(benefit)
Effective income tax rate
Year Ended December 31,
2018
2017
2016
(In millions, except percentages)
$
$
467
98
18
—
7
—
—
(106)
—
—
—
(7)
1
—
(4)
—
7
1.5%
(1,389)
(486)
19
2
—
665
(660)
455
(5)
30
—
(8)
(5)
—
(64)
13
(44)
3.2%
$
$
(931)
(326)
—
10
—
—
—
382
22
—
1
(7)
2
(59)
—
—
25
(2.7)%
$
$
For the year ended December 31, 2018, NRG's overall effective tax rate was different than the federal statutory tax rate of
21% primarily due to a tax benefit for the change in valuation allowance, the generation of PTCs from various wind facilities and
establishment of the previously sequestered AMT credit receivable, partially offset by current state tax expense.
For the year ended December 31, 2017, NRG's overall effective tax rate was different than the federal statutory tax 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 and the generation of PTCs 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.
For the year ended December 31, 2016, NRG's overall effective tax rate was different than the federal statutory tax rate of
35% primarily due to the change in valuation allowance and the impact of non-taxable equity earnings, partially offset by the state
tax rate change and the generation of PTCs from various wind facilities.
171
The temporary differences, which gave rise to the Company's deferred tax assets and liabilities consisted of the following:
As of December 31,
2018
2017
(In millions)
$
15
37
180
—
21
1
36
290
134
554
11
38
87
9
14
—
2,241
62
379
1
381
6
21
102
7
17
4,064
(3,812)
19
271
(19) $
15
17
337
1
2
5
49
426
141
611
38
52
74
10
14
1
596
66
128
1
368
7
98
—
12
185
2,402
(1,855)
(8)
539
113
As of December 31,
2018
2017
(In millions)
$
46
—
(65)
(19) $
6
128
(21)
113
$
$
$
$
Deferred tax liabilities:
Emissions allowances
Derivatives, net
Investment in projects
Discount/premium on notes
Deferred financing costs
Other
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)
Interest disallowance carryforward per §163(j) of the Tax Act
Inventory obsolescence
Discontinued operations
Total deferred tax assets
Valuation allowance
Discontinued operations
Total deferred tax assets, net of valuation allowance
Net deferred tax (liability)/asset
The following table summarizes NRG's net deferred tax position:
Deferred tax asset — continuing operations
Deferred tax asset — discontinued operations
Deferred tax liability— continuing operations
Net deferred tax (liability)/asset
172
The primary driver for the decrease in the net deferred tax asset from $113 million as of December 31, 2017 to a net deferred
tax liability of $19 million as of December 31, 2018 is the removal of NRG Yield, Inc.'s net deferred tax asset upon their sale in
2018. The 2017 beginning deferred balance included $128 million of NRG Yield Inc.'s net deferred tax assets, which were
subsequently moved to discontinued operations prior to the sale.
Deferred tax assets and valuation allowance
Net deferred tax balance — As of December 31, 2018 and 2017, NRG recorded a net deferred tax asset of $3.8 billion and
$2.0 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
determination is based on the Company's assessment of cumulative and forecasted pretax book earnings and the future reversal
of existing taxable temporary differences.
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 $3.8 billion and $1.9 billion of tax assets as of
December 31, 2018, and 2017, respectively, thus a valuation allowance has been recorded. The net deferred tax liability of $19
million as of December 31, 2018 is predominantly due to a foreign net deferred tax liability of $16 million and a net deferred tax
liability for the state of Texas.
NOL carryforwards — At December 31, 2018, the Company had tax effected cumulative domestic NOLs consisting of
carryforwards for federal income tax purposes of $2.2 billion and state of $379 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 2031. In addition,
NRG has cumulative foreign NOL carryforwards of $62 million with no expiration date.
Valuation allowance — As of December 31, 2018, the Company's tax effected valuation allowance was $3.8 billion, consisting
of domestic federal net deferred tax assets of approximately $3.3 billion, domestic state net deferred tax assets of $454 million,
foreign NOL carryforwards of $62 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, 2018, NRG recorded a current tax payable of $3 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.
Uncertain tax benefits
NRG has identified uncertain tax benefits whose after-tax value is $26 million and $30 million, as of December 31, 2018
and 2017, for which NRG has recorded a non-current tax liability of $30 million and $33 million, respectively. The Company
recognizes interest and penalties related to uncertain tax benefits in income tax expense. During the year ended December 31,
2018, the Company recognized an expense of $1 million in interest. As of December 31, 2018 and 2017, NRG had cumulative
interest and penalties related to these uncertain tax benefits of $4 million and $3 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.
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.
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
173
As of December 31,
2018
2017
(In millions)
$
$
30
4
—
(8)
26
$
$
34
4
(8)
—
30
Note 19 — Stock-Based Compensation
NRG Energy, Inc. Long-Term Incentive Plan
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, 2018 and 2017, a total of 25,000,000 shares of NRG common stock were authorized for issuance under the NRG
LTIP. There were 8,564,611 and 8,724,595 shares of common stock remaining available for grants under the NRG LTIP as of
December 31, 2018 and 2017, 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, 2018 and 2017, there were 520,182 and 1,369,880 shares of
common stock remaining available for grants under the NRG GenOn LTIP, respectively.
Non-Qualified Stock Options
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 2018, 2017 or 2016.
The following table summarizes the Company's NQSO activity and changes during the year:
Outstanding at December 31, 2017
Expired
Exercised
Outstanding at December 31, 2018
Exercisable at December 31, 2018
Shares(a)
Weighted Average
Exercise Price
$
1,285,858
(36,866)
(969,058)
279,934
279,934
25.49
43.64
24.93
25.04
25.04
Weighted Average
Remaining Contractual
Term
(In years)
Aggregate
Intrinsic Value
(In millions)
3
$
2
2
6
4
4
(a) As of December 31, 2018, 26,430 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
2018
Year Ended December 31,
2017
(In millions)
2016
$
$
10
24
$
1
4
—
—
There were no options exercised during the year ended December 31, 2016.
Restricted Stock Units
As of December 31, 2018, 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, 2017
Granted
Forfeited
Vested
Non-vested at December 31, 2018
(a) As of December 31, 2018, 7,319 RSUs granted to GenOn employees remain outstanding
Units(a)
2,377,813
447,309
(315,569)
(1,051,471)
1,458,082
Weighted Average Grant
Date Fair Value per Unit
14.63
$
28.90
18.93
17.67
16.16
The total fair value of RSUs vested during the years ended December 31, 2018, 2017, and 2016, was $42 million, $19 million,
and $11 million, respectively. The weighted average grant date fair value of RSUs granted during the years ended December 31,
2018, 2017, and 2016 was $28.90, $12.44, and $11.54, respectively.
174
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, 2017
Granted
Converted to Common Stock
Outstanding at December 31, 2018
(a) There were no DSUs granted to GenOn employees and outstanding as of December 31, 2018 and 2017
Units(a)
427,148
61,645
(156,878)
331,915
Weighted Average Grant
Date Fair Value per Unit
21.54
$
33.43
23.59
22.94
The aggregate intrinsic values for DSUs outstanding as of December 31, 2018, 2017, and 2016 were approximately $13
million, $12 million, and $6 million, respectively. The aggregate intrinsic values for DSUs converted to common stock for the
years ended December 31, 2018, 2017, and 2016 were $0 million, $4 million, and $1 million, respectively. The weighted average
grant date fair value of DSUs granted during the years ended December 31, 2018, 2017, and 2016 was $33.43, $16.76, and $16.85,
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, 2018, 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.
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, 2017
Granted
Forfeited
Vested
Non-vested at December 31, 2018
(a) There were no PSUs granted to GenOn employees and outstanding as of December 31, 2018
175
Units(a)
1,858,821
372,147
(134,473)
(385,861)
1,710,634
Weighted Average Grant-
Date Fair Value per Unit
18.27
$
35.36
22.26
30.31
19.12
The weighted average grant date fair value of PSUs granted during the years ended December 31, 2018, 2017 and 2016, was
$35.36, $15.91 and $14.73, 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
2018
RPSUs
2017
RPSUs
2016
MSUs
47.52%
3
2.01%
43.96%
3
1.5%
34.33%
3
1.31%
For the years ended December 31, 2018 and 2017, 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, 2018, for each of the types of awards issued under the LTIPs. Minimum tax withholdings of $19 million, $5 million,
and $5 million for the years ended December 31, 2018, 2017, and 2016, respectively, are reflected as a reduction to additional
paid-in capital on the Company's consolidated balance sheets and are reflected as operating activities on the Company's consolidated
statements of cash flows.
Compensation Expense
Year Ended December 31,
Non-vested Compensation Cost
Unrecognized
Total Cost
Weighted Average
Recognition Period
Remaining (In years)
As of December 31,
Award
2018
2017
2016
2018
2018
(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, 2018, 2017, and 2016
(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 compensation expense of $1 million, $6 million, and $4 million for each of the years ended December 31, 2018, 2017, and 2016, which
was recorded in loss from discontinued operations in the Company's consolidated statements of operations
— $
12
2
4
7
16
41
$
(4) $
— $
12
2
2
—
4
20
(4)
— $
15
2
5
3
13
38
$
(5) $
0.00
0.89
0.00
0.03
1.32
1.17
—
9
—
—
10
14
33
$
$
$
176
Note 20 — Related Party Transactions
The following table summarizes NRG's material related party transactions with third party affiliates:
Revenues from Related Parties Included in Operating Revenues
Gladstone
GenConn
Ivanpah
Midway-Sunset
Total
Year Ended December 31,
2018
2017
(In millions)
2016
$
$
3
4
20
5
32
$
$
3
5
—
—
8
$
$
2
5
—
—
7
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. NRG no longer has an ownership interest in GenConn
as a result of the sale of its ownership interests in NRG Yield, Inc. and its Renewables Platform.
Ivanpah — NRG provides services to Ivanpah, an equity method investment as of May 1, 2018, under an operations and
maintenance agreement. Fees for the services under this contract primarily include recovery of NRG's costs of operating the plant
plus a profit margin.
Midway-Sunset — NRG provides services to Midway-Sunset, an equity method investment, under an operations and
maintenance agreement. Fees for the 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 and an annual incentive bonus.
Services Agreement and Transition Services Agreement with GenOn
The Company 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, or the Services Agreement. The annual fees under the
Services Agreement was approximately $193 million and management had concluded that this method of charging overhead costs
was reasonable. In connection with the Restructuring Support Agreement in 2017, NRG agreed to provide shared services to
GenOn under the Services Agreement for an adjusted annualized fee of $84 million.
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 provided the
shared services and other separation services at an annualized rate of $84 million, subject to certain credits and adjustments. GenOn
provided notice to NRG of its intent to terminate the transition services agreement effective August 15, 2018 and in connection
with the settlement agreement described in Note 3, Acquisitions, Discontinued Operations and Dispositions, all amounts owed
and payable to NRG were settled against the $28 million credit provided for in the Restructuring Support Agreement. For the year
ended December 31, 2018, NRG recorded approximately $53 million, under the transition services agreement against selling,
general and administrative expenses post-Chapter 11 Filing. 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.
Credit Agreement with GenOn
NRG and GenOn were 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.
As a result of the GenOn bankruptcy, no additional revolving loans or letters of credit were available to GenOn. As of December 31,
2017, $92 million of letters of credit were issued and outstanding. As a result of the GenOn Settlement, as further described in
Note 3, Acquisitions, Discontinued Operations, and Dispositions, outstanding borrowings were repaid to NRG, except for certain
LCs issued which are further discussed below. The facility was terminated on December 14, 2018.
On December 7, 2018, NRG, GenOn and REMA entered into an agreement to support the outstanding LCs from the
intercompany revolving credit agreement previously issued. As of December 31, 2018, $30 million was outstanding. GenOn
177
and REMA have provided support for these outstanding LCs through back-to-back letters of credit and cash collateral. The
outstanding letters of credit will continue to accrue any contractual fees and expenses until they are terminated.
Commercial Operations Agreement
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, 2018, 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, 2018 and December 31, 2017, the Company had $4 million and $32 million, respectively, of
cash collateral posted in support of energy risk management activities by GenOn.
Note 21 — 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 Midwest
Generation the Company recorded in 2014 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. This accounting will change effective January 1, 2019 upon the adoption of ASU 2016-02 as discussed further in Note 2,
Summary of Significant Accounting Policies - Recent Accounting Developments - Guidance Not Yet Adopted.
Future minimum lease commitments under the Powerton and Joliet operating leases for the years ending after December 31,
2018 are as follows:
Period
2019
2020
2021
2022
2023
Thereafter
Total
Other Operating Leases
(In millions)
1
1
3
6
6
222
239
$
$
NRG leases certain Company facilities and equipment under operating leases, some of which include escalation clauses,
expiring on various dates through 2036. 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
$66 million, $69 million, and $85 million for the years ended December 31, 2018, 2017, and 2016, respectively.
178
Future minimum lease commitments under operating leases for the years ending after December 31, 2018 are as follows:
Period(a)
2019
2020
2021
2022
2023
Thereafter
Total
(In millions)
60
55
43
40
39
95
332
$
$
(a) Amounts in the table exclude future sublease income of $29 million associated with long-term leases for office locations
Coal, Gas and Transportation Commitments
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, 2018, 2017, and 2016, the Company purchased $1.2 billion, $1.0 billion,
and $1.1 billion, respectively, under such arrangements.
As of December 31, 2018, the Company's commitments under such outstanding agreements are as follows:
Period
2019
2020
2021
2022
2023
Thereafter
Total
(In millions)
227
156
122
74
55
209
843
$
$
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, 2018.
Minimum purchase commitment obligations are as follows as of December 31, 2018:
Period
2019
2020
2021
2022
2023
Thereafter
Total (a)
(a) As of December 31, 2018, the maximum remaining term under any individual purchased power contract is ten years
First Lien Structure
(In millions)
30
13
12
11
1
1
68
$
$
NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired
in the EME (including Midwest Generation) acquisitions, 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, 2018, hedges under the first lien
were out-of-the-money for NRG on a counterparty aggregate basis.
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Lignite Contract with Texas Westmoreland Coal Co.
The Company's Limestone facility historically blended lignite obtained from the Jewett mine, which was operated by Texas
Westmoreland Coal Co, or TWCC, and coal sourced from the Powder River Basin in Wyoming. 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 approximately $99 million on TWCC for the
reclamation of the mine. Pursuant to the contract with TWCC, NRG supports this obligation through surety bonds. Additionally,
under the terms of the contract, NRG is obligated to provide additional performance assurance if required by the Railroad
Commission of Texas.
On October 9, 2018, TWCC and certain of its affiliates filed for protection under Chapter 11 of the U.S. Bankruptcy Code
before the Bankruptcy Court for the Southern District of Texas. TWCC has obtained authorization from the Bankruptcy Court to
continue to perform its obligations under its contract with the Company and to maintain surety bond programs throughout its
operations. In addition, NRG has not received any indication from the Railroad Commission of Texas of an intent to draw on the
surety bonds. TWCC has filed a plan of reorganization that, if confirmed, would provide for the assumption and/or assignment of
the contract with NRG. Unless the Jewett mine and other related assets of TWCC are sold to another third party before the plan
of reorganization is consummated, TWCC and/or its assets, including the Jewett mine and related agreements with NRG, will be
owned upon the consummation of the plan by a new entity that is initially owned and controlled by certain holders of TWCC’s pre-
bankruptcy funded indebtedness. The Bankruptcy Court is currently expected to consider confirmation of the plan in late February,
unless adjourned to a later date. However, given the uncertainty involved in bankruptcy proceedings, it is uncertain whether these
transactions will be consummated and whether and to what extent TWCC’s bankruptcy may, in the future, impact the reclamation
costs incurred by NRG or the surety bonds.
Nuclear Insurance
STP maintains required insurance coverage for liability claims arising from nuclear incidents pursuant to the Price-Anderson
Act. Effective September 10, 2018, the current liability limit per incident is $14.07 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, 2023. 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 $13.4 billion in funds available for public liability claims. The current maximum assessment per incident, per reactor,
is approximately $138 million, taking into account a 5% adjustment for administrative fees, payable at approximately $21 million
per year, per reactor. NRG would be responsible for 44% of the maximum assessment, or $9 million per year, per reactor, and a
maximum of $61 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 $14 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, and European Mutual Association for Nuclear Insurance, or EMANI, both of which are industry mutual insurance
companies, 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 non-nuclear event limit is expected to reduce to $1.0 billion effective April 1, 2019). The nuclear event
limit remains 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 $3 million per unit up to a maximum of $274 million nuclear
per unit and $184 million non-nuclear per unit, 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 $216 million nuclear and $144 million non-nuclear, and
is subject to an eight-week waiting period. Under the terms of the NEIL and EMANI policies, member companies may be assessed
up to ten and six times their annual premiums respectively if the NEIL or EMANI 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 and EMANI
require that their 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
and EMANI to guarantee the Company's obligation; however note the NEIL aspect of 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.
180
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. On
March 27, 2018, ComEd filed a Motion to Compel Payments of Claims seeking $61 million related to asbestos liabilities. On April
25, 2018, NRG filed an Omnibus Objection to All Remaining Claims of ComEd and Exelon. A trial before the Bankruptcy Court
to determine the amount of ComEd’s claims is currently scheduled for April 10, 2019.
California Department of Water Resources and San Diego Gas & Electric Company v. Sunrise Power Company LLC - On
January 29, 2016, CDWR and SDG&E (plaintiffs) filed a lawsuit against Sunrise Power Company, along with NRG and Chevron
Power Corporation (defendants). 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, plaintiffs filed a notice of appeal. On
January 10, 2018, plaintiffs filed their opening appellate brief. Defendants filed their opposition brief on April 10, 2018. On May
30, 2018, plaintiffs filed their reply brief. The case is now waiting for the court of appeal to schedule oral argument.
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. After oral
argument on April 24, 2018, the Appellate Division reversed the lower court on May 4, 2018, and ordered that the plaintiff must
arbitrate their claims against NRG. On May 23, 2018, the plaintiff filed a petition for certification with the Supreme Court of New
Jersey seeking to overturn the Appellate Division ruling. On January 25, 2019, the Supreme Court denied plaintiff’s petition for
certification.
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
181
its answer and affirmative defenses on November 17, 2017. On February 4, 2019, NRG sold the South Central Portfolio, including
the entities subject to this litigation. However, NRG has agreed to indemnify the purchaser for certain losses suffered in connection
therewith.
GenOn Chapter 11 Cases - 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 GenOn's
Chapter 11 plan, which provides for, among other things, GenOn’s transition to a standalone enterprise. GenOn's Chapter 11 plan
became effective on December 14, 2018.
Note 22 — Regulatory Matters
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.
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.
Zero-Emission Credits for Nuclear Plants in Illinois and New York - 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 two Exelon-
owned nuclear power plants in Illinois. That same year, the NYSPSC issued its Clean Energy Standard, or CES, which provides
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 New York. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and
interfere with the wholesale power market. NRG, along with other companies, filed complaints in the federal courts of Illinois
and New York alleging that these state programs are preempted by federal law and in violation of the dormant commerce clause.
These cases have proceeded through the federal district court as well as the federal appellate court in Illinois and New York,
respectively. On January 7, 2019, NRG and its trade association filed a Petition for Writ of Certiorari with the United States
Supreme Court in both cases.
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.
South Central - On August 4, 2016, NRG received a document hold notice from FERC regarding conduct in the MISO
and PJM markets. It required NRG to retain communications related to multiple generating units in the South Central region.
Since sending the notice, FERC has been investigating potential violations of MISO rules involving bidding for the Big Cajun
2 facility, as well as other aspects of NRG’s operations in MISO. FERC has the authority to require disgorgement of profits and
to impose penalties and NRG retains any liability following the sale of the South Central Portfolio. We expect a preliminary
finding from FERC by the second quarter of 2019.
ISO-NE - On February 5, 2019, FERC has informed the Company that it has made a preliminary finding that the
Company violated FERC's market behavior rules in connection with offers made into the ISO-NE Forward Capacity Auction in
2016. The Company understands that FERC is concerned that the Company was inaccurate in its communications with the
Market Monitor regarding the costs and risks associated with operating certain units in the forward timeframe. Ultimately, the
Company opted to withdraw the relevant bids prior to the auction in 2016. The Company will be engaging in discussions with
FERC regarding this matter.
182
Note 23 — 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.
Air
On August 31, 2018, EPA proposed replacing the Clean Power Plan (CPP) rule, which sought to broadly regulate CO2
emissions from the power sector, with the Affordable Clean Energy (ACE) rule, which if finalized, would require states to develop
plans to seek heat rate improvements from coal-fired EGUs. The Company believes that the ACE rule replacing the CPP rule
would on balance be positive for its generation fleet.
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. In December 2018, the EPA proposed a finding that regulating HAPs was not "appropriate and
necessary" because the costs far exceed the benefits. Nonetheless, the EPA proposed keeping the substantive requirements of the
MATS rule. 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
Once Through Cooling Regulation — 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, the Company anticipates the cost of complying with these requirements to be immaterial.
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. In 2017, the EPA agreed to reconsider the rule. On July 30, 2018, the EPA promulgated a rule that amends the
existing ash rule by extending some of the deadlines and providing more flexibility for compliance. On August 21, 2018, the D.C.
Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy ponds. Accordingly, we
anticipate that the EPA will promulgate new regulations to address these issues (including compliance deadlines) as it reconsiders
other aspects of the existing rule. The EPA has stated that it intends to further revise the rule. The Company will provide estimates
of the cost of compliance after the rule is revised.
For further discussion of these matters, refer to Note 21, Commitments and Contingencies.
183
Note 24 — 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, net of refunds
Non-cash investing and financing activities:
Additions to fixed assets for accrued capital expenditures
Note 25 — Guarantees
Year Ended December 31,
2018
2017
2016
(In millions)
$
436
$
543
$
9
20
9
19
606
14
9
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:
By Remaining Maturity at December 31,
2018
Guarantees
Under
1 Year
1-3 Years
3-5 Years
Over
5 Years
Total
2017 Total
Letters of credit and surety bonds(a)(b)
Asset sales guarantee obligations
Other guarantees
Total guarantees
$
$
1,138
—
—
1,138
$
$
79
4
105
188
$
$
(In millions)
— $
257
—
257
$
36
532
616
1,184
$
$
1,253
793
721
2,767
$
$
1,003
312
645
1,960
(a) As of December 31, 2017 excludes $92 million of letters of credit issued under the intercompany revolving credit agreement between NRG and GenOn
(b) December 31, 2018 includes $32 million of letter of credit and surety bonds for the benefit of GenOn where NRG holds cash or letter of credit to back stop
the liability
Letters of credit and surety bonds — As of December 31, 2018, NRG and its consolidated subsidiaries were contingently
obligated for a total of $1.3 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, except as
described in Note 3, Acquisitions, Discontinued Operations and Dispositions.
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.
184
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 26 — 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, 2018
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
Cedar Bayou Unit 4, Baytown, TX
44.00% $
50.00%
$
382
215
(185) $
(84)
5
8
185
Note 27 — Unaudited Quarterly Financial Data
Refer to Note 3, Acquisitions, Discontinued Operations and Dispositions, and Note 9, 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
2018
December 31
September 30
June 30
March 31
Operating revenues
Operating income
Net (loss)/income from continuing operations
Income/(loss) from discontinued operations
Net (loss)/income
Less: Net (loss)/income attributable to noncontrolling
interests and redeemable noncontrolling interests
(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
(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)
2,461
$
174
27
69
2,960
398
288
(336)
(48)
1,992
49
(93)
80
(13)
(2)
(11) $
24
(72) $
289
299
0.28
$
(1.12) $
(0.04) $
(0.24) $
289
299
0.28
$
(1.12) $
(0.04) $
(0.24) $
96
24
72
310
0.22
0.23
314
0.22
0.23
$
$
$
$
$
$
$
Quarter Ended
2017
December 31
September 30
June 30
2,154
(1,200)
(1,390)
(265)
(1,655)
(120)
$
(In millions, except per share data)
2,281
$
214
60
(702)
(642)
2,618
275
163
—
163
(8)
(16)
(1,535) $
171
$
(626) $
317
317
316
(0.84) $
— $
(2.22) $
(4.84) $
0.54
$
(1.98) $
317
322
316
(0.84) $
— $
(2.22) $
(4.84) $
0.53
$
(1.98) $
186
2,065
361
238
(5)
233
(46)
279
318
(0.02)
0.88
322
(0.02)
0.87
March 31
2,021
(30)
(178)
(25)
(203)
(40)
(163)
316
(0.08)
(0.52)
316
(0.08)
(0.52)
Note 28 — Condensed Consolidating Financial Information
As of December 31, 2018, the Company had outstanding $4.4 billion of Senior Notes due 2022 to 2048, as shown in Note
11, 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.
Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior
Notes as of December 31, 2018:
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 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 Retail 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
NRG Distributed Energy Resources Holdings
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.
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 Generation PR LLC
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
Louisiana Generating LLC
Meriden Gas Turbines LLC
Middletown Power LLC
Montville Power LLC
NEO Corporation
New Genco GP, LLC
Norwalk Power 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.
187
NRG Retail Northeast LLC
NRG Rockford Acquisition LLC
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 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
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 11, Debt and Capital Leases, to the consolidated
financial statements. For a discussion of NRG Energy, Inc.'s contingencies, see Note 21, Commitments and Contingencies, to the
consolidated financial statements. For a discussion of NRG Energy, Inc.'s guarantees, see Note 25, Guarantees, to the consolidated
financial statements.
188
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2018
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
NRG Energy, Inc.
(Note Issuer)
Eliminations (a)
Consolidated
Balance
(In millions)
$
8,119
$
1,385
$
— $
(26) $
9,478
959
150
93
63
—
1
1,266
28
147
—
10
(15)
(13)
—
(49)
(67)
80
19
61
75
136
28
33
—
348
86
11
506
—
(506)
(26)
—
—
(74)
—
(1)
(101)
—
75
7,108
421
99
799
90
11
8,528
32
982
1,291
(1,314)
—
(1)
—
(1)
(44)
(420)
825
319
(384)
703
(329)
374
—
—
—
—
—
(1,314)
(1,239)
—
(1,239)
—
(1,239)
9
(15)
18
(44)
(483)
(515)
467
7
460
(192)
268
(181)
317
$
106
268
$
75
(1,314) $
—
268
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
Gain on sale of assets
Operating Income/(Loss)
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries
Equity in earnings/(losses) of unconsolidated
affiliates
Impairment losses on investments
Other income/(expense), net
Loss on debt extinguishment, net
Interest expense
Total other income/(expense)
Income from Continuing Operations Before
Income Taxes
Income tax expense/(benefit)
Income from Continuing Operations
Income/(Loss) from Discontinued Operations, net
of income tax
Net Income
Less: Net (loss)/income attributable to
noncontrolling interests and redeemable
noncontrolling interests
6,147
238
6
462
4
—
6,857
4
1,266
23
—
—
32
—
(14)
41
1,307
372
935
62
997
—
Net Income Attributable to NRG Energy, Inc.
$
997
$
(a) All significant intercompany transactions have been eliminated in consolidation
189
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the Year Ended December 31, 2018
Net Income
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 (loss)/income
Comprehensive Income
Less: Comprehensive (loss)/income attributable to
noncontrolling interests and redeemable
noncontrolling interests
Comprehensive Income Attributable to NRG
Energy, Inc.
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
NRG Energy,
Inc.
(Note Issuer)
Eliminations(a)
Consolidated
Balance
$
997
$
136
$
(In millions)
374
$
(1,239) $
268
—
(10)
—
(9)
(19)
978
29
(10)
—
—
19
155
9
(13)
1
(35)
(38)
336
(15)
22
—
9
16
(1,223)
—
(166)
104
76
$
978
$
321
$
232
$
(1,299) $
23
(11)
1
(35)
(22)
246
14
232
(a) All significant intercompany transactions have been eliminated in consolidation
190
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2018
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
Prepayments and other current assets
Current assets - held-for-sale
Current assets - discontinued operations
Total current assets
Property, plant and equipment, net
Other Assets
Investment in subsidiaries
Equity investments in affiliates
Goodwill
Intangible assets, net
Nuclear decommissioning trust fund
Derivative instruments
Deferred income taxes
Other non-current assets
Non-current assets - held-for-sale
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 expenses and other current liabilities
Current liabilities - held-for-sale
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
Derivative instruments
Deferred income taxes
Out-of-market contracts, net
Other non-current liabilities
Non-current liabilities - held-for-sale
Non-current liabilities - discontinued operations
Total non-current liabilities
Total Liabilities
Redeemable noncontrolling interest in subsidiaries
Stockholders' Equity
$
55
33
7
894
278
779
275
460
180
—
177
3,138
1,938
446
—
359
422
663
296
6
133
—
405
2,730
$
28
—
10
82
134
50
12
33
32
1
20
402
957
—
412
214
169
—
4
(143)
71
77
607
1,411
480
—
—
43
—
16
—
266
90
—
—
895
153
4,707
—
—
—
—
22
183
97
—
—
5,009
$
— $
—
—
—
—
(81)
—
(754)
—
—
—
(835)
—
(5,153)
—
—
—
—
(5)
—
(12)
—
—
(5,170)
563
33
17
1,019
412
764
287
5
302
1
197
3,600
3,048
—
412
573
591
663
317
46
289
77
1,012
3,980
7,806
$
2,770
$
6,057
$
(6,005) $
10,628
— $
693
675
713
33
291
—
24
2,429
244
282
371
114
306
112
—
288
—
58
1,775
4,204
—
3,602
$
55
64
(249)
41
—
36
5
48
—
192
—
—
1
3
61
121
198
65
577
1,218
1,218
19
1,533
$
17
105
329
—
—
353
—
—
804
6,025
—
—
320
—
(108)
—
232
—
—
6,469
7,273
—
(1,216)
— $
—
(754)
(81)
—
—
—
—
(835)
(12)
—
—
—
(5)
—
—
—
—
—
(17)
(852)
—
(5,153)
72
862
1
673
33
680
5
72
2,398
6,449
282
371
435
304
65
121
718
65
635
9,445
11,843
19
(1,234)
10,628
Total Liabilities and Stockholders' Equity
$
7,806
$
2,770
$
6,057
$
(6,005) $
(a) All significant intercompany transactions have been eliminated in consolidation
191
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2018
Guarantor
Subsidiaries
Non-Guarantor
Subsidiaries
NRG Energy, Inc.
(Note Issuer)
(In millions)
Eliminations(a)
Consolidated
Balance
Cash Flows from Operating Activities
Net income
Income/(loss) from discontinued operations
Net income from continuing operations
Adjustments to reconcile net income to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates
Depreciation, amortization and accretion
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/cost 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
Changes in nuclear decommissioning trust liability
GenOn settlement, net of insurance proceeds
Net loss on deconsolidation of Agua Caliente and Ivanpah projects
Changes in other working capital
Cash provided/(used) by continuing operations
Cash provided by discontinued operations
Net Cash Provided/(Used) by Operating Activities
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired
Capital expenditures
Net 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 of cash disposed and sale of discontinued
operations, net of fees
Deconsolidation of Agua Caliente and Ivanpah projects
Changes in investments in unconsolidated affiliates
Net (contributions to)/distributions from discontinued operations
Other
Cash (used)/provided by continuing operations
Cash used by discontinued operations
Net Cash (Used)/Provided by Investing Activities
Cash Flows from Financing Activities
Payments (for)/from intercompany loans
Payments of dividends to preferred and common stockholders
Payments for treasury stock
Payments for debt extinguishment costs
Net distributions to noncontrolling interests from subsidiaries
Proceeds from issuance of common stock
Proceeds from issuance of long-term debt
Payments of debt issuance costs
Payments for short and long-term debt
Receivable from affiliate
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 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
$
$
997
62
935
$
136
75
61
$
374
(329)
703
$
(1,239)
—
(1,239)
—
266
79
48
—
—
36
—
(30)
5
25
372
(94)
60
—
—
311
2,013
89
2,102
(40)
(192)
19
(572)
513
14
—
—
—
—
(258)
—
(258)
(1,701)
—
—
—
—
—
—
—
—
—
—
(1,701)
—
(1,701)
—
89
54
41
47
160
6
—
6
—
9
—
(20)
109
15
5
(11)
—
—
13
(193)
207
285
492
(203)
(151)
—
—
—
8
(268)
(39)
(60)
—
(713)
(725)
(1,438)
113
—
—
—
(16)
—
163
—
(138)
—
(4)
118
471
589
1
31
(387)
425
(1)
33
—
—
23
44
—
25
1
—
11
(372)
—
—
(63)
—
(1,621)
(1,217)
—
(1,217)
—
(45)
—
—
—
1,542
—
—
—
(6)
1,491
—
1,491
1,588
(37)
(1,250)
(32)
—
21
937
(19)
(1,596)
(26)
—
(414)
—
(414)
—
—
(140)
620
—
—
—
—
—
—
—
—
—
—
(14)
—
—
—
—
—
1,253
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
268
(192)
460
46
459
85
48
29
44
45
25
(49)
114
37
5
(105)
60
(63)
13
(250)
1,003
374
1,377
(243)
(388)
19
(572)
513
1,564
(268)
(39)
(60)
(6)
520
(725)
(205)
—
(37)
(1,250)
(32)
(16)
21
1,100
(19)
(1,734)
(26)
(4)
(1,997)
471
(1,526)
1
120
(473)
1,086
$
95
$
38
$
480
$
— $
613
192
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2017
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
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries
Equity in losses of unconsolidated affiliates
Impairment losses on investments
Other income, net
Loss on debt extinguishment, net
Interest expense
Total other income/(expense)
Loss from Continuing Operations Before
Income Taxes
Income tax (benefit)/expense
Income/(Loss) from Continuing Operations
Income/(Loss) from Discontinued Operations, net
of income tax
Net Income/(Loss)
Less: Net loss 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
$
7,818
$
1,304
$
— $
(48) $
9,074
5,998
343
1,346
410
6
—
8,103
—
4
(281)
18
—
—
9
—
(14)
13
(268)
(598)
330
91
421
—
862
221
188
64
—
4
1,339
—
12
(23)
—
(10)
(75)
14
—
(91)
(162)
(185)
(62)
(123)
(420)
(543)
(168)
72
32
—
364
38
18
524
87
—
(437)
28
(4)
(4)
28
(49)
(452)
(453)
(890)
616
(1,506)
(663)
(2,169)
(16)
(46)
—
—
(2)
—
—
(48)
—
—
—
(46)
—
—
—
—
—
(46)
(46)
—
(46)
—
(46)
—
6,886
596
1,534
836
44
22
9,918
87
16
(741)
—
(14)
(79)
51
(49)
(557)
(648)
(1,389)
(44)
(1,345)
(992)
(2,337)
(184)
$
421
$
(375) $
(2,153) $
(46) $
(2,153)
(a) All significant intercompany transactions have been eliminated in consolidation
193
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the Year Ended December 31, 2017
Net Income/(Loss)
Other Comprehensive Income/(Loss), 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 Income/(Loss)
Less: Comprehensive loss attributable to
noncontrolling interests and redeemable
noncontrolling interests
Comprehensive Income/(Loss) Attributable to
NRG Energy, Inc.
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
NRG Energy,
Inc.
(Note Issuer)
(In millions)
Eliminations(a)
Consolidated
Balance
$
421
$
(543) $
(2,169) $
(46) $
(2,337)
1
6
—
(13)
(6)
415
13
7
—
30
50
(493)
25
—
(8)
41
58
(2,111)
—
(103)
(16)
(26)
(1)
—
(12)
(39)
(85)
(60)
13
12
(8)
46
63
(2,274)
(179)
$
415
$
(390) $
(2,095) $
(25) $
(2,095)
(a) All significant intercompany transactions have been eliminated in consolidation
194
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
Prepayments and other current assets
Current assets - held-for-sale
Current assets - discontinued operations
Total current assets
Property, plant and equipment, net
Other Assets
Investment in subsidiaries
Equity investments in affiliates
Goodwill
Intangible assets, net
Nuclear decommissioning trust fund
Derivative instruments
Deferred income taxes
Other non-current assets
Non-current assets - held for sale
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 expenses and other current liabilities
Accrued expenses and other current liabilities - affiliate
Current liabilities - held-for-sale
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
Derivative instruments
Deferred income taxes
Out-of-market contracts, net
Other non-current liabilities
Non-current liabilities - held-for-sale
Non-current liabilities - discontinued operations
Total non-current liabilities
Total Liabilities
Redeemable noncontrolling interest in subsidiaries
Stockholders' Equity
Total Liabilities and Stockholders' Equity
$
— $
37
4
852
307
647
170
685
106
8
89
2,905
2,052
266
—
359
455
692
126
377
64
—
456
2,795
7,752
$
— $
582
725
556
37
313
—
—
34
2,247
244
269
415
118
136
112
—
284
—
73
1,651
3,898
—
3,854
7,752
$
(a) All significant intercompany transactions have been eliminated in consolidation
195
150
—
275
44
146
24
1
183
30
108
655
1,616
3,689
—
181
180
55
—
2
(135)
126
43
10,072
10,524
15,829
183
47
(310)
38
—
67
—
72
807
904
2,197
—
—
1
7
64
129
198
8
6,725
9,329
10,233
78
5,518
15,829
$
$
$
$
620
—
—
4
—
10
—
(154)
27
—
—
507
237
8,234
1
—
—
—
31
(236)
120
—
—
8,150
8,894
21
55
176
—
—
376
161
—
5
794
6,739
—
—
339
—
(155)
—
52
—
—
6,975
7,769
—
1,125
8,894
$
$
$
$
— $
—
—
—
—
(57)
—
(534)
—
—
—
(591)
(4)
(8,500)
—
—
(3)
—
—
—
—
—
(22)
(8,525)
(9,120) $
— $
—
(534)
(57)
—
—
—
—
—
(591)
—
—
—
—
—
—
—
—
—
—
—
(591)
—
(8,529)
(9,120) $
770
37
279
900
453
624
171
180
163
116
744
4,437
5,974
—
182
539
507
692
159
6
310
43
10,506
12,944
23,355
204
684
57
537
37
756
161
72
846
3,354
9,180
269
415
458
143
21
129
534
8
6,798
17,955
21,309
78
1,968
23,355
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2017
Cash Flows from Operating Activities
Net income/(loss)
Income/(loss) from discontinued operations
Net income/(loss) from continuing operations
Adjustments to reconcile net income/(loss) to net cash provided by operating
activities:
Distributions and equity in earnings of unconsolidated affiliates
Depreciation, amortization and accretion
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/(gain) on sale of assets and equity/cost 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
Changes in nuclear decommissioning trust liability
Changes in other working capital
Cash provided/(used) by continuing operations
Cash provided by discontinued operations
Net Cash Provided/(Used) by Operating Activities
Cash Flows from Investing Activities
Acquisition of businesses, net of cash acquired
Capital expenditures
Proceeds from renewable energy grants
Net 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 of cash disposed and sale of discontinued
operations, net of fees
Changes in investments in unconsolidated affiliates
Net distributions from discontinued operations
Other
Cash (used)/provided by continuing operations
Cash used by discontinued operations
Net Cash (Used)/Provided by Investing Activities
Cash Flows from Financing Activities
Payments (for)/from intercompany loans
Payment of dividends to preferred and common stockholders
Payments for debt extinguishment costs
Net distributions to noncontrolling interests from subsidiaries
Payments for issuance of common stock
Proceeds from issuance of long-term debt
Payment of debt issuance costs
Payments for short and long-term debt
Receivable from affiliate
Other
Cash (used)/provided by continuing operations
Cash used 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 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)
Eliminations(a)
Consolidated
Balance
(In millions)
$
$
421
91
330
$
(543)
(420)
(123)
$
(2,169)
(663)
(1,506)
$
(46)
—
(46)
(2,337)
(992)
(1,345)
—
343
56
51
—
—
42
—
2
1,346
(214)
(300)
(98)
11
82
1,651
116
1,767
(14)
(180)
—
66
(512)
501
33
—
—
18
(88)
(13)
(101)
(1,525)
—
—
—
—
—
—
—
—
—
(1,525)
(109)
(1,634)
—
(6)
38
3
12
221
—
—
13
—
12
—
(11)
264
50
(9)
18
—
(354)
93
638
731
—
(43)
8
—
—
—
54
(57)
—
4
(34)
(966)
(1,000)
(39)
—
—
(30)
—
94
(2)
(183)
—
(8)
(168)
(60)
(228)
(1)
(388)
(110)
535
90
32
12
—
16
49
—
35
—
4
(4)
322
—
—
62
(888)
—
(888)
—
(31)
—
—
—
—
343
—
150
—
462
—
462
1,564
(38)
(42)
—
(2)
1,084
(16)
(1,701)
(125)
—
724
—
724
—
—
298
322
—
—
—
—
—
—
—
—
—
—
(2)
—
—
—
48
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
102
596
68
51
29
49
54
35
(9)
1,614
(170)
13
(80)
11
(162)
856
754
1,610
(14)
(254)
8
66
(512)
501
430
(57)
150
22
340
(979)
(639)
—
(38)
(42)
(30)
(2)
1,178
(18)
(1,884)
(125)
(8)
(969)
(169)
(1,138)
(1)
(394)
226
860
$
41
$
425
$
620
$
— $
1,086
(a) All significant intercompany transactions have been eliminated in consolidation
196
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2016
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/(Loss) 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. Eliminations (a)
Consolidated
Balance
(In millions)
$
7,539
$
1,450
$
— $
(74) $
8,915
5,581
1,116
500
370
430
—
6,881
—
(1)
657
(50)
5
—
5
—
(15)
(55)
602
(1)
603
86
689
230
113
144
18
1,621
—
—
(171)
—
(9)
(252)
15
(4)
(85)
(335)
(506)
28
(534)
—
(534)
59
26
—
458
30
573
193
(79)
(459)
374
(4)
(16)
27
(138)
(483)
(240)
(699)
(2)
(697)
(21)
(718)
(80)
—
—
—
—
(80)
—
—
6
(324)
(10)
—
—
—
—
(334)
(328)
—
(328)
—
(328)
6,676
756
483
1,032
48
8,995
193
(80)
33
—
(18)
(268)
47
(142)
(583)
(964)
(931)
25
(956)
65
(891)
—
(169)
56
(4)
(117)
689
$
(365) $
(774) $
(324) $
(774)
(a) All significant intercompany transactions have been eliminated in consolidation
197
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)
For the Year Ended December 31, 2016
Guarantor
Subsidiaries
Non-
Guarantor
Subsidiaries
NRG Energy,
Inc.
(Note Issuer)
(In millions)
Eliminations(a)
Consolidated
Balance
Net Income/(Loss)
$
689
$
(534) $
(718) $
(328) $
(891)
Other Comprehensive Income/(Loss), 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 interest
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
—
(1)
—
44
43
732
—
732
—
—
32
(1)
—
(13)
18
(516)
(103)
(413)
—
—
89
(1)
1
(51)
38
(680)
56
(736)
5
(78)
(86)
2
—
23
(61)
(389)
(70)
(319)
—
—
35
(1)
1
3
38
(853)
(117)
(736)
5
(78)
$
732
$
(413) $
(663) $
(319) $
(663)
(a) All significant intercompany transactions have been eliminated in consolidation
198
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/(loss) from discontinued operations
Net income/(loss) from continuing operations
Adjustments to reconcile net income/(loss) to net cash provided/(used) by
operating activities:
Distributions and equity in earnings of unconsolidated affiliates
Depreciation, amortization and accretion
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/cost 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
Changes in nuclear decommissioning trust liability
Changes in other working capital
Cash provided/(used) by continuing operations
Cash provided by discontinued operations
Net Cash Provided/(Used) by Operating Activities
Cash Flows from Investing Activities
Acquisition of business, net of cash acquired
Capital expenditures
Proceeds from renewable energy grants
Net purchases 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 of cash disposed and sale of discontinued
operations, net of fees
Changes in investments in unconsolidated affiliates
Net distributions to discontinued operations
Other
Cash (used)/provided by continuing operations
Cash used by discontinued operations
Net Cash (Used)/Provided by Investing Activities
Cash Flows from Financing Activities
Payments (for)/from intercompany loans
Payment of dividends to preferred and common stockholders
Payment for preferred shares
Payments for debt extinguishment costs
Net distributions to noncontrolling interest from subsidiaries
Proceeds from issuance of common stock
Proceeds from issuance of long-term debt
Payments of debt issuance costs
Payments for short and long-term debt
Other
Cash (used)/provided by continuing operations
Cash (used)/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
$
$
689
86
603
$
(534)
—
(534)
$
(718)
(21)
(697)
$
(328)
—
(328)
(5)
508
42
49
—
—
56
—
70
370
28
(1)
384
41
(139)
2,006
174
2,180
—
(172)
—
(1)
(551)
510
—
—
—
27
(187)
(9)
(196)
(1,856)
—
—
—
—
—
—
—
(2)
(3)
(1,861)
(163)
(2,024)
—
2
(42)
45
(14)
238
3
—
13
4
12
—
—
365
21
49
12
—
(54)
115
297
412
—
(326)
36
—
—
—
56
(33)
—
4
(263)
(379)
(642)
375
—
—
—
(27)
—
271
—
(221)
(4)
394
646
1,040
1
564
247
288
86
26
—
—
20
138
—
10
69
16
(36)
(60)
—
—
(256)
(684)
—
(684)
—
(46)
—
—
—
—
185
—
(58)
—
81
—
81
1,481
(76)
(226)
(121)
—
1
4,141
(61)
(4,923)
—
216
—
216
—
—
(387)
709
—
—
—
—
—
—
—
—
—
—
3
—
—
—
325
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(891)
65
(956)
67
772
45
49
33
142
68
10
139
751
16
(12)
396
41
(124)
1,437
471
1,908
—
(544)
36
(1)
(551)
510
241
(33)
(58)
31
(369)
(388)
(757)
—
(76)
(226)
(121)
(27)
1
4,412
(61)
(5,146)
(7)
(1,251)
483
(768)
1
566
(182)
1,042
$
3
$
535
$
322
$
— $
860
(a) All significant intercompany transactions have been eliminated in consolidation
199
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2018, 2017, and 2016
Allowance for doubtful accounts, deducted from
accounts receivable
Year Ended December 31, 2018
Year Ended December 31, 2017
Year Ended December 31, 2016
Income tax valuation allowance, deducted from
deferred tax assets
Year Ended December 31, 2018
Year Ended December 31, 2017
Year Ended December 31, 2016
Balance at
Beginning of
Period
Charged to
Costs and
Expenses
Charged to
Other Accounts
(In millions)
Deductions
Balance at
End of Period
$
$
28
28
21
83
57
55
$
1,863
$
4,116
3,575
1,934
(151)
306
$
$
— $
—
—
(79) (a) $
(57) (a)
(48) (a)
32
28
28
(128) $
(15)
235
125 (b) $
(2,087) (c)
—
3,794
1,863
4,116
(a) Represents principally net amounts charged as uncollectible
(b) Represents removal of NRG Yield, Inc. and its Renewables Platform due to their sale on August 31, 2018
(c) Represents deconsolidation of GenOn due to its petition for bankruptcy on June 14, 2017
200
Number
Description
Method of Filing
EXHIBIT INDEX
2.1
2.2
2.3
2.4
2.5
2.6†^
2.7^
3.1
3.2
3.3
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
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.
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.
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.
Incorporated herein by reference to Exhibit 2.9 to the
Registrant's annual report on Form 10-K filed on March
1, 2018.
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.
Incorporated herein by reference to Exhibit 2.10 to the
Registrant's annual report on Form 10-K filed on March
1, 2018.
Amended and Restated Certificate of Incorporation.
Certificate of Amendment to Amended and Restated Certificate of
Incorporation.
Fourth Amended and Restated By-Laws.
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.
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.
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.
Form of 8.25% Senior Note due 2020.
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-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.
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 4.4 to the
Registrant's current report on Form 8-K filed on
May 25, 2011.
201
4.9
4.10
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.
4.11
Form of 7.875% Senior Note due 2021.
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22
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.
202
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.
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.
4.23
Form of 6.625% Senior Note due 2023.
4.24
4.25
4.26
4.27
4.28
4.29
4.30
4.31
4.32
4.33
4.34
4.35
4.36
4.37
4.38
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.
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.
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.
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
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.
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 4.2 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.
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.
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.
203
4.39
4.40
4.41
4.42
4.43
4.44
4.45
4.46
4.47
4.48
4.49
4.50
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.
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.
4.51
Form of 6.25% Senior Note due 2022.
4.52
4.53
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.
204
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.
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.
4.54
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.
4.55
Form of 6.25% Senior Note due 2024.
4.56
4.57
4.58
4.59
4.60
4.61
4.62
4.63
4.64
4.65
4.66
4.67
4.68
4.69
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.
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 4.1 to the
Registrant's current report on Form 8-K filed on
November 25, 2014.
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.
205
4.76
4.77
4.78
4.79
4.80
4.70
4.71
4.72
4.73
4.74
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.
4.75
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.
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.
4.81
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.
4.82
4.83
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.
4.84
Form of 5.75% Senior Notes due 2028
4.85
4.86
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.
Indenture, dated May 24, 2018, among NRG Energy, Inc., the
guarantors named therein and Delaware Trust Company, as trustee.
4.87
Form of 2.75% Convertible Senior Notes due 2048.
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 4.1 to the
Registrant's Current Report on Form 8-K, filed on May
25, 2018.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant's Current Report on Form 8-K, filed on May
25, 2018.
206
10.1*
10.2*
10.3*
10.4*
10.5*
10.6*
10.7*
10.8†
10.9*
10.10
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.
Form of NRG Energy, Inc. Long-Term Incentive Plan Restricted Stock
Unit Agreement for Officers.
Form of NRG Energy, Inc. Long-Term Incentive Plan Restricted Stock
Unit Agreement for Non-Officers.
Form of NRG Energy, Inc. Long-Term Incentive Plan Performance
Stock Unit Agreement.
Second Amended and Restated Annual Incentive Plan for Designated
Corporate Officers.
LLC Membership Interest Purchase Agreement between Reliant
Energy, Inc. and NRG Retail LLC, dated as of February 28, 2009.
The NRG Energy, Inc. Amended and Restated Long-Term Incentive
Plan.
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.
10.11*
NRG 2010 Stock Plan for GenOn Employees.
10.12*
10.13*
NRG Energy, Inc. Long-Term Incentive Plan Market Stock Unit
Agreement.
NRG Energy, Inc. 2010 Stock Plan For GenOn Employees Market
Stock Unit Agreement
10.14*
Amended and Restated Employee Stock Purchase Plan.
10.15
10.16
10.17
10.18
10.19
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 10.14 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.
Incorporated herein by reference to Exhibit 10.6 to the
Registrant's annual report on Form 10-K filed on March
1, 2018.
Incorporated herein by reference to Exhibit 10.7 to the
Registrant's annual report on Form 10-K filed on March
1, 2018.
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.
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 April
28, 2017.
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 10.53 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.
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.
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.
207
10.20
10.21
10.22
10.23
10.24
10.25*
10.26*
10.27†
10.28
10.29
10.30*
21.1
23.1
31.1
31.2
31.3
32
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.
Form of NRG Energy, Inc. Long-Term Incentive Plan Relative
Performance Stock Unit Agreement for Senior Vice Presidents.
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).
Second Amendment Agreement, dated as of March 21, 2018, 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.
Third Amendment Agreement, dated as of May 7, 2018, by and among
NRG Energy, Inc., its subsidiaries parties thereto, the lenders from
time to time parties thereto and Citicorp North America, Inc., as
administrative agent and collateral agent.
NRG Energy, Inc. Amended and Restated Executive Change-in-
Control and General Severance Plan for Tier IA and Tier IIA
Executives (Amended and Restated Effective April 1, 2018).
Incorporated herein by reference to Exhibit 10.73 to the
Registrant's annual report on Form 10-K filed on March
1, 2018.
Incorporated herein by reference to Exhibit 10.74 to the
Registrant's annual report on Form 10-K filed on March
1, 2018.
Incorporated herein by reference to Exhibit 10.34 to
NRG Yield, Inc.'s Annual Report on Form 10-K filed on
March 1, 2018.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's Current Report on Form 8-K filed on March
22, 2018.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's Current Report on Form 8-K filed on May
7, 2018.
Incorporated herein by reference to Exhibit 10.2 to the
Registrant's Quarterly Report on Form 10-Q filed on
August 2, 2018.
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
208
None.
209
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.
SIGNATURES
NRG ENERGY, INC.
(Registrant)
By:
/s/ MAURICIO GUTIERREZ
Mauricio Gutierrez
Chief Executive Officer
Date: February 28, 2019
210
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints Brian E. Curci and Christine A. Zoino, 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 February 28, 2019.
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/ MATTHEW CARTER, JR.
Matthew Carter, Jr.
/s/ HEATHER COX
Heather Cox
/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/ THOMAS H. WEIDEMEYER
Thomas H. Weidemeyer
Title
President, Chief Executive Officer and
Director (Principal Executive Officer)
Chief Financial Officer
(Principal Financial Officer)
Chief Accounting Officer
(Principal Accounting Officer)
Date
February 28, 2019
February 28, 2019
February 28, 2019
Chairman of the Board
February 28, 2019
February 28, 2019
February 28, 2019
February 28, 2019
February 28, 2019
February 28, 2019
February 28, 2019
February 28, 2019
February 28, 2019
Director
Director
Director
Director
Director
Director
Director
Director
211
NRG Energy
804 Carnegie Center
Princeton, NJ
08540-6213
t: 609.524.4500
f: 609.524.4501
nrg.com
910 Louisiana St.
Houston, TX
77002-6929
t: 713.537.3000