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, 2021.
☐ 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.)
910 Louisiana Street, Houston, Texas
(Address of principal executive offices)
77002
(Zip Code)
(713) 537-3000
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common Stock, par value $0.01
Trading Symbol(s)
NRG
Name of Exchange on Which Registered
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 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 has filed a report on and attestation to its management's assessment of the effectiveness of its internal
control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C 7262(b)) by the registered public accounting firm that prepared
or issued its audit report ☒
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 $8,611,281,553 based on the closing sale price of $40.30 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 February 24, 2022
242,153,239
Documents Incorporated by Reference:
Portions of the Registrant's definitive Proxy Statement relating to its 2022 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
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 — Reserved
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
Item 9C— Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
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
7
7
24
39
40
41
41
42
42
43
44
73
76
76
76
79
79
80
80
80
80
81
81
82
82
166
160
2
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
ACE
Affordable Clean Energy
Adjusted EBITDA
Adjusted earnings before interest, taxes, depreciation and amortization
Glossary of Terms
ARO
ASC
ASU
AUC
Average realized prices
Bankruptcy Code
Bankruptcy Court
Baseload
Brazos
BTU
Business
CAA
CAISO
CARES Act
Carlsbad
CCR
CDD
Centrica
CES
CFTC
Cleco
CO2
CO2e
ComEd
Company
Convertible Senior Notes
Cottonwood
COVID-19
CPP
CPUC
CWA
D.C. Circuit
Distributed Solar
DSI
DSU
Dual fuel customers
Economic gross margin
EGU
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
Alberta Utilities Commission
Volume-weighted average power prices, net of average fuel costs and reflecting the impact
of settled hedges
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
Brazos Electric Power Cooperative, Inc.
British Thermal Unit
NRG Business, which serves business customers
Clean Air Act
California Independent System Operator
Coronavirus Aid, Relief, and Economic Security Act
Carlsbad Energy Center, a 528 MW natural gas-fired project located in Carlsbad, CA
Coal Combustion Residuals
Cooling Degree Day
Centrica plc
Clean Energy Standard
U.S. Commodity Futures Trading Commission
Cleco Corporate Holdings LLC
Carbon Dioxide
Carbon Dioxide Equivalents
Commonwealth Edison
NRG Energy, Inc.
As of December 31, 2021, consists of NRG’s $575 million unsecured 2.75% Convertible
Senior Notes due 2048
Cottonwood Generating Station, a 1,177 MW natural gas-fueled plant
Coronavirus Disease 2019
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
Dry Sorbent Injection
Deferred Stock Unit
Customer that have both electricity and natural gas service with the Company
Sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of
fuels and other cost of sales
Electric Generating Unit
3
EPA
EPC
ERCOT
ESCO
ESP
ESPP
U.S. Environmental Protection Agency
Engineering, Procurement and Construction
Electric Reliability Council of Texas, the Independent System Operator and the regional
reliability coordinator of the various electricity systems within Texas
Energy Service Companies
Electrostatic Precipitator
NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan
Exchange Act
The Securities Exchange Act of 1934, as amended
FASB
FERC
FGD
FPA
FTRs
GAAP
GenOn
GenOn Entities
GHG
GIP
Financial Accounting Standards Board
Federal Energy Regulatory Commission
Flue gas desulfurization
Federal Power Act
Financial Transmission Rights
Generally accepted accounting principles in the U.S.
GenOn Energy, Inc.
GenOn and certain of its wholly owned subsidiaries, including GenOn Americas
Generation, LLC, that filed voluntary petitions for relief under Chapter 11 of the
Bankruptcy Code in the Bankruptcy Court on June 14, 2017
Greenhouse Gas
Global Infrastructure Partners
Green Mountain Energy
Green Mountain Energy Company
GW
GWh
HDD
Heat Rate
HLBV
HLW
Home
ICE
ISO
ISO-NE
Ivanpah
kWh
LaGen
LIBOR
LSE
LTIPs
MATS
MDth
Merger
Midwest Generation
MISO
MMBtu
MMDth
Gigawatts
Gigawatt Hours
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
NRG Home, which serves residential customers
Intercontinental Exchange
Independent System Operator, also referred to as RTOs
ISO New England Inc.
Ivanpah Solar Electric Generation Station, a 393 MW solar thermal power plant located in
California's Mojave Desert in which NRG owns 54.5% interest
Kilowatt-hours
Louisiana Generating LLC
London Inter-Bank Offered Rate
Load Serving Entities
Collectively, the NRG LTIP and the NRG GenOn LTIP
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, LLC
Midcontinent Independent System Operator, Inc.
Million British Thermal Units
Million Dekatherms
4
MSU
MW
MWe
MWh
NAAQS
NEIL
NEPOOL
NERC
Net Capacity Factor
Net Exposure
Net Generation
Net Revenue Rate
NOL
NOx
NPNS
NQSO
NRC
NRG
NRG GenOn LTIP
NRG LTIP
NRG Yield, Inc.
Nuclear Decommissioning
Trust Fund
Nuclear Waste Policy Act
NYISO
NYMEX
NYSDEC
OCI/OCL
ORDC
ORDPA
Peaking
Petra Nova
Pipeline
PJM
PM2.5
PPA
PPM
PSU
PUCT
Rayburn
RCRA
Market Stock Unit
Megawatts
Megawatt equivalent
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
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
Sum of retail revenues less TDSP transportation charges
Net Operating Loss
Nitrogen Oxides
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 its 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 Department of Environmental Conservation
Other Comprehensive Income/(Loss)
Operating Reserve Demand Curve
Online Reliability Deployment Price Adder
Units expected to satisfy demand requirements during the periods of greatest or peak load
on the system
Petra Nova Parish Holdings, LLC
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
Public Utility Commission of Texas
Rayburn Country Electric Cooperative, Inc.
Resource Conservation and Recovery Act of 1976
5
Receivables Securitization
Facilities
RECs
Renewables
Renewables Platform
Revolving Credit Facility
Collectively, the Receivables Facility and the Repurchase Facility
Renewable Energy Certificates
Consists of the following projects in which NRG has an ownership interest: Agua Caliente,
Ivanpah, and solar generating stations located at various NFL Stadiums
The renewable operating and development platform sold to GIP with NRG's interest in
NRG Yield.
The Company's $3.7 billion revolving credit facility as of December 31, 2021, a component
of the Senior Credit Facility, due 2024 was amended on May 28, 2019 and August 20, 2020
RGGI
RMR
RPS
RPSU
RSU
RTO
SCR
SEC
Securities Act
Senior Credit Facility
Senior Notes
Senior Secured Notes
SNF
SO2
South Central Portfolio
S&P
STP
STPNOC
Tax Act
TDSP
Texas Genco
TSR
TWCC
TWh
U.S.
U.S. DOE
VaR
VIE
Winter Storm Uri
Regional Greenhouse Gas Initiative
Reliability Must-Run
Renewable Portfolio Standards
Relative Performance Stock Unit
Restricted Stock Unit
Regional Transmission Organization
Selective Catalytic Reduction Control System
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. The 2023 Term Loan Facility was repaid in the second quarter of
2019
As of December 31, 2021, NRG's $4.6 billion outstanding unsecured senior notes
consisting of $375 million of the 6.625% senior notes due 2027, $821 million of 5.75%
senior notes due 2028, $733 million of the 5.25% senior notes due 2029, $500 million of
the 3.375% senior notes due 2029, $1.0 billion of the 3.625% senior notes due 2031 and
$1.1 billion of the 3.875% senior notes due 2032
As of December 31, 2021, NRG’s $2.5 billion outstanding Senior Secured First Lien Notes
consists of $600 million of the 3.75% Senior Secured First Lien Notes due 2024, $500
million of the 2.0% Senior Secured First Lien Notes due 2025, $900 million of the 2.45%
Senior Secured First Lien Notes due 2027, and $500 million of the 4.45% Senior Secured
First Lien Notes due 2029
Spent Nuclear Fuel
Sulfur Dioxide
NRG's South Central Portfolio, which owned and operated a portfolio of generation assets
consisting of Bayou Cove, Big Cajun-I, Big Cajun-II, Cottonwood and Sterlington, was
sold on February 4, 2019. NRG is leasing back the Cottonwood facility through May 2025
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
Transmission/distribution service provider
Texas Genco LLC
Total Shareholder Return
Texas Westmoreland Coal Co.
Terawatt Hours
United States of America
U.S. Department of Energy
Value at Risk
Variable Interest Entity
A major winter and ice storm that had widespread impacts across North America occurring
in February 2021
6
Item 1 — Business
General
PART I
NRG Energy, Inc., or NRG or the Company, is a consumer services company built on dynamic retail brands. NRG brings
the power of energy to customers by producing and selling energy and related products and services, nation-wide in the U.S.
and Canada in a manner that delivers value to all of NRG's stakeholders. NRG sells power, natural gas, and home and power
services, and develops innovative, sustainable solutions, predominately under the brand names NRG, Reliant, Direct Energy,
Green Mountain Energy, Stream, and XOOM Energy. The Company has a customer base that includes approximately 6 million
Home customers as well as commercial, industrial, and wholesale customers, supported by approximately 18,000 MW of
generation as of December 31, 2021.
NRG sold 157 TWhs of electricity and 1,877 MMDth of natural gas in 2021, making it one of the largest competitive
energy retailers in the U.S. As of the end of 2021, NRG had recurring electricity and/or natural gas sales in 24 U.S. states, the
District of Columbia, and 8 provinces in Canada. NRG's retail brands, collectively, have the largest share of competitively
served residential electric customers in Texas and nationwide.
The following chart represents NRG's sales volumes for the year ended December 31, 2021:
Strategy
NRG's strategy is to maximize stakeholder value through the safe production and sale of reliable electricity and natural
gas to its customers in the markets it serves, while positioning the Company to provide innovative solutions to the end-use
energy or service customer. This strategy is intended to enable the Company to optimize its integrated model to generate stable
and predictable cash flow, significantly strengthen earnings and cost competitiveness, and lower risk and volatility.
Sustainability is a philosophy that underpins and facilitates value creation across our business for our stakeholders. It is an
integral piece of NRG's strategy and ties directly to business success, reduced risks and enhanced reputation.
To effectuate the Company’s strategy, NRG is focused on: (i) serving the energy needs of end-use residential, commercial
and industrial, and wholesale customers in competitive markets through multiple brands and channels; (ii) offering a variety of
energy products and services, including renewable energy solutions, that are differentiated by innovative features, premium
service, sustainability, and loyalty/affinity programs; (iii) excellence in operating performance of its assets; (iv) optimal hedging
of its portfolio; and (v) engaging in disciplined and transparent capital allocation.
The 2021 fiscal year was pivotal for the Company. NRG completed the acquisition of Direct Energy, doubling the size of
its retail portfolio, while further decreasing its physical generation through the sale and planned retirement of certain assets,
each as further discussed below. The completion of these significant activities positioned NRG for the next phase of its strategy
focusing on growth.
7
The Company implemented a four-year plan beginning in 2022 to invest up to $2 billion in order to achieve growth
through optimization of the Company's core power and natural gas sales, as well as integrated solution sales within its core
network in both power and home services.
Significant Acquisitions, Dispositions and Announced Retirements
On January 5, 2021, the Company acquired Direct Energy. Direct Energy is a leading retail provider of electricity, natural
gas, and home and business energy-related products and services in North America, with operations in all 50 U.S. states and 8
Canadian provinces. The acquisition increased NRG's retail portfolio by over 3 million customers and complemented its
integrated model. It also broadened the Company's presence in the Northeast and in states and locales where it did not
previously operate, supporting NRG's objective to diversify its business. NRG realized its planned synergy target of $175
million in 2021 and expects to realize annual synergies of $225 million and $300 million in 2022 and 2023, respectively. See
Item 15 — Note 4, Acquisitions, Discontinued Operations and Dispositions, to the Consolidated Financial Statements for
further discussion of the acquisition of Direct Energy.
On December 1, 2021, the Company sold approximately 4,850 MWs of fossil generating assets from its East and West
regions of operations to Generation Bridge, an affiliate of ArcLight Capital Partners. As part of the transaction, NRG entered
into a tolling agreement for the 866 MW Arthur Kill plant in New York City through April 2025. See Item 15 — Note 4,
Acquisitions, Discontinued Operations and Dispositions, to the Consolidated Financial Statements for further discussion.
During the second quarter of 2021, the results of the PJM Base Residual Auction for the 2022/2023 delivery year were
released, leading the Company to announce the near-term retirement of approximately 1,600 MW of its PJM coal generating
assets in June 2022. On July 30, 2021, PJM identified reliability impacts resulting from the proposed deactivation of one of
those assets, Indian River Unit 4. On August 27, 2021 the Company notified PJM that it would continue operations at Indian
River Unit 4 until the reliability upgrades identified by PJM were completed, provided that the unit receives a satisfactory and
compensatory reliability must run arrangement. See Item 15 — Note 11, Asset Impairments, to the Consolidated Financial
Statements for further discussion. The Company is continuing to evaluate the viability of the remaining PJM generating assets.
Extreme Weather Event in Texas During February 2021 and expected Uplift Securitization proceeds
During February 2021, Texas experienced unprecedented cold temperatures for a prolonged duration as a result of Winter
Storm Uri, resulting in a power emergency, blackouts, and an estimated all-time peak demand of 77 GW (without load shed).
Ahead of the event, NRG launched residential customer communications calling for conservation across all of its brands, and
initiated residential and commercial and industrial demand response programs to curtail customer load. The Company
maximized available generating capacity and brought in additional resources to supplement in-state staff with technical and
operating experts from the rest of its U.S. fleet.
The Texas Legislature passed House Bill ("HB") 4492, which among other things, authorized ERCOT to obtain $2.1
billion of financing to distribute to LSEs that were charged and paid to ERCOT exceptionally highly priced ORDPA and
ancillary service costs during Winter Storm Uri (the "Uplift Securitization"). NRG will receive $689 million from ERCOT
based on LSE-level detail published by the PUCT on December 7, 2021.
During the year ended December 31, 2021, Winter Storm Uri's pre-tax financial impact to the Company was a loss of
$380 million, which reflects the recovery of $689 million of cost of operations as a result of the proceeds NRG will receive
from the Uplift Securitization discussed above, with receipt expected to occur during the second quarter of 2022. The Company
continues to pursue additional mitigants including, but not limited to, customer bad debt mitigation, counterparty default
recovery, and additional ERCOT default recovery.
Business Overview
The Company’s core business is the sale of electricity and natural gas to residential, commercial and industrial and
wholesale customers, supported by the Company's wholesale generation. NRG manages its operations based on the combined
results of the retail and wholesale generation businesses with a geographical focus.
The Company's business is segmented as follows:
• Texas, which includes all activity related to customer, plant and market operations in Texas;
• East, which includes all activity related to customer, plant and market operations in the East;
• West/Services/Other, which primarily includes the following assets and activities: (i) all activity related to customer,
plant and market operations in the West and Canada, (ii) the services businesses, (iii) activity related to the
Cottonwood facility, (iv) the remaining renewables activity, including the Company’s equity method investment in
Ivanpah Master Holdings, LLC, and (v) activity related to the Company’s equity method investment for the Gladstone
power plant in Australia; and
• Corporate activities.
8
As of December 31, 2021, in Texas, the Company’s generation supply is fully integrated with its retail load. In the East,
the Company’s retail load is more dispersed throughout the region and not fully integrated with the Company’s generation
supply due to the locations of its power plants in that region. In the West/Services/Other, the Company’s business is primarily
serving retail load and services customers.
The Company’s integrated model consists of three core functions: Customer Operations, Market Operations and Plant
Operations, which directly support each other in each geographic region. The Company’s integrated model in Texas provides
the advantage of being able to supply a significant portion of the Company’s retail customers with electricity from the
Company’s assets, which reduces the need to sell electricity to and buy electricity from other institutions and intermediaries,
resulting in stable earnings and cash flows, lower transaction costs and less credit exposure. The integrated model also results in
a reduction in actual and contingent collateral through offsetting transactions, thereby reducing transactions with third parties.
Customer Operations
Customer Operations is responsible for growing and retaining the customer base and delivering an outstanding customer
experience. This includes acquisition and retention of all of NRG’s residential, small commercial, government and commercial
& industrial customers. NRG employs a multi-brand strategy that leverages a wide array of sales and partnership channels,
direct face-to-face sales channels, call centers, websites, and brokers. Go-to-market activities include market strategy planning
and development, product innovation, offer design, campaign execution, marketing and creative services, and selling. Customer
portfolio maintenance and retention activities include fulfillment, billing, payment processing, collections, customer service,
issue resolution, and contract renewals. NRG provides energy and related services at either fixed, indexed or month-to-month
prices. Home customers typically contract for terms ranging from one month to five years, while Business contracts are often
between one year and five years in length. Throughout all Customer Operations activities, the customer experience is kept at the
forefront to inform decision-making and optimize retention, while creating supporters and advocates for NRG’s brands in the
market. Following the expansion of the customer base with the acquisition of Direct Energy, Customer Operations now
comprises three end-use customer facing teams: NRG Home, which serves residential customers, NRG Business, which serves
business customers, and NRG Services, which primarily includes the services businesses acquired.
Product Offerings
NRG sells a variety of products to residential and small commercial customers, including retail electricity and energy
management, natural gas, home security, line and surge protection products, HVAC installation, repair and maintenance, home
protection products, carbon offsets, back-up power stations, portable power, portable solar and portable lighting. Home and
Services customers make purchase decisions based on a variety of factors, including price, incentive, customer service, brand,
innovative offers/features and referrals from friends and family. Through its broad range of service offerings and value
propositions, NRG is able to attract, retain, and increase the value of its customer relationships. NRG's brands are recognized
for exemplary customer service, innovative smart energy and technology product offerings, and environmentally-friendly
solutions.
The Company provides power and natural gas to the business-to-business markets in North America, as well as retail
services, including demand response, commodity sales, energy efficiency and energy management solutions to Business
customers. The Company is an integrated provider of supply and distributed energy resources and focuses on distributed
products and services as businesses seek greater reliability, cleaner power and other benefits that they cannot obtain from the
grid. These solutions include system power, distributed generation, renewable 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 Business customers.
Market Operations
Market Operations has two primary objectives: (i) to supply energy to our customers in the most cost-efficient manner;
and (ii) to maximize the value of the Company's assets after satisfying its customer load requirements. These objectives are
intended to reduce supply costs and maximize earnings with predictable cash flows.
Power and natural gas are the two main commercial groups within market operations.
Power
The power commercial group is responsible for end-use electricity supply including power plant optimization and certain
fuel supply. To meet the market operations objectives, NRG enters into supply, power and gas sales and hedging agreements
via a wide range of products and contracts, including (i) physical and financial commodity instruments, (ii) fuel supply and
transportation contracts, (iii) renewable PPAs and (iv) capacity and other contracted revenue sources, as further discussed
below.
9
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.
Physical and Financial Commodity Instruments
NRG trades electric power, natural gas and related commodities, environmental products, weather products and financial
products, including forwards, futures, options and swaps. NRG enters into these instruments primarily to manage price and
delivery risk, optimize physical and contractual assets in the portfolio, manage working capital requirements, reduce the carbon
exposure in its business and comply with laws.
Fuel Supply and Transportation Contracts
NRG's fuel requirements consist of various forms of fossil fuel and nuclear fuel. The prices of fossil fuels can be volatile.
The Company obtains its fossil fuels from multiple suppliers and through multiple transporters. Although availability is
generally not an issue, localized shortages, transportation availability, delays arising from extreme weather conditions and
supplier financial stability issues can and do occur. The preceding factors related to the sources and availability of raw materials
are fairly uniform across the Company's business and fuel products used. NRG's primary fuel requirements consist of the
following:
Natural Gas — NRG operates a fleet of mid-merit and peaking natural gas plants. Fuel needs are managed by the natural
gas commercial group, 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 as the dispatch is highly unpredictable.
Coal —NRG actively manages its coal requirements based on forecasted generation, market volatility and its inventory on
site. The Company believes it is adequately hedged, using forward coal supply agreements, for its domestic coal consumption
for 2022. As of December 31, 2021, NRG had purchased forward contracts to provide fuel for approximately 88% of the
Company's expected requirements for 2022 and 2023. For the domestic fleet, NRG purchased approximately 16.1 million tons
of coal in 2021, almost all of which was Powder River Basin coal. For fuel transport, NRG has entered into various rail
transportation and rail car lease agreements with varying tenors that will provide for most of the Company's transportation
requirements of Powder River Basin coal for the next three years.
Nuclear Fuel — STP's owners, including NRG, 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 that is 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 (through 2027/2028). Similarly, STP has begun the process of covering fuel supply requirements into
the extended license period and has secured a fabrication contract with Westinghouse through 2047/2048. Other fuel
requirements such as uranium, conversion and enrichment remain open at this time.
Renewable PPAs
The Company's strategy is to procure mid to long-term renewable generation through power purchase agreements. As of
December 31, 2021, NRG has entered into PPAs totaling approximately 2.6 GW with third-party project developers and other
counterparties. The average tenor of these agreements is twelve years. The Company expects to continue evaluating and
executing similar agreements that support the needs of the business. The total GW entered into through PPAs may be impacted
by contract terminations when they occur.
Capacity and Other Contracted Revenue Sources
NRG's revenues and cash flows, primarily in the East and West, 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.
The Company's largest sources of continuing capacity revenues are capacity auctions in PJM and NYISO. PJM operates a
pay-for-performance model where capacity payments are modified based on real-time performance and NRG's actual revenues
will be the combination of revenues based on the cleared auction MW plus the net of any over- and under-performance of
NRG's respective generation assets. The Company primarily sells physical and financial capacity forward through bilateral
contracts for our New York state assets. To the extent NRG is not able to enter into physical bilateral contracts, NRG will sell
the remaining capacity into the NYISO six-month strip, monthly or spot auctions.
10
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.
Natural Gas
The natural gas commercial group is responsible for all costing, logistics and supply for all of NRG's residential,
commercial & industrial and wholesale customers. The Direct Energy acquisition, which closed on January 5, 2021,
significantly increased our capabilities and scale across the natural gas value chain. NRG has acquired contractual rights to
natural gas transportation and storage assets across its footprint that allow for optimal supply economics in support of our
various businesses. Our diversified load coupled with this asset portfolio enables us to deliver supply economically while
providing incremental optimization activities when market conditions allow. The scale of the natural gas operation extends from
the wellhead (through our producer services business) to our end use customers (through our various sales channels). This scale,
coupled with our associated assets, gas system platform and people, create significant opportunity across North America.
Plant Operations
The Company owns and leases a diversified wholesale generation portfolio with approximately 18,000 MW of fossil fuel,
nuclear and renewable generation capacity at 25 plants as of December 31, 2021, including approximately 1,600 MW of its
PJM coal fleet with an announced retirement date of June 2022. The Company's wholesale generation assets are diversified by
fuel-type and dispatch level, which helps mitigate the risks associated with fuel price volatility and market demand cycles. NRG
continually evaluates its generation portfolio to focus on asset optimization opportunities and the locational value of its
generation assets in each of the markets where the Company participates, as well as opportunities for the development of new
generation.
The following table summarizes NRG's generation portfolio as of December 31, 2021:
Type
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Utility Scale Solar . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Battery Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(In MW)(a)
Texas
East
West/Services/
Other
Total
4,775
4,174
—
1,132
—
2
1,881
3,140
455
—
—
—
1,494
605
—
—
219
—
8,150
7,919
455
1,132
219
2
Total generation capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10,083
5,476
2,318
17,877
(a)
All Utility Scale Solar 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.
Plant Operations is responsible for operating the Company's generation facilities at the highest standards of safety and
reliability, and includes (i) operations and maintenance, (ii) asset management, and (iii) development, engineering and
construction.
Operations & Maintenance
NRG operates and maintains its generation portfolio, as well as approximately 7,377 MW of additional coal and natural
gas generation capacity at 12 plants operated on behalf of third parties as of December 31, 2021 using prudent industry
practices for the safe, reliable and economic generation of electricity in compliance with all local, state and federal
requirements. The Company follows a consistent set of operating requirements, including a solid base of training, required
adherence to specific safety and environmental limits, procedure and checklist usage, and the implementation of continuous
process improvement through incident investigations.
NRG uses best-in-class maintenance practices for preventive, predictive, and corrective maintenance planning. The
Company’s strategic planning process evaluates equipment condition, performance, and obsolescence to support the
development of a comprehensive work scope and schedule for long-term performance.
11
Asset Management
NRG manages all aspects of its generation portfolio to optimize the lifecycle value of the assets, consistent with the
Company’s goals. The Company evaluates capital projects required for continued operation and strategic enhancement of the
assets, provides quality assurance on capital outlays, and assesses the impact of rules, regulations, and laws on business
profitability. In addition, the Company manages its long-term contracts, PPAs, and real estate holdings and provides third party
asset management services.
Development, Engineering & Construction
NRG develops, engineers and executes major plant modifications, “new build” generation and energy storage projects that
enhance the value of its generation portfolio and provide options to meet generation growth needs in the retail markets we
serve, in accordance with the Company’s strategic goals. Projects have included gas-fired generation development and
construction, coal to gas conversions, grid scale energy storage development, grid scale renewable construction, and asset
demolition, remediation and reclamation work.
Operational Statistics
The following statistics represent the Company's retail load and customer count:
Year ended December 31,
2020
2019
2021
Sales volumes - Electricity (in GWh)
Home - Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Home - East . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Home - West/Services/Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business - Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business - East . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business - West/Services/Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
42,397
14,108
2,252
34,367
53,204
10,625
Total Load . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
156,953
38,473
10,221
—
17,928
1,596
—
68,218
38,958
9,918
—
18,976
1,214
—
69,066
Sales volumes - Natural gas (in MDth)
Home - East . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Home - West/Services/Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
74,920
97,272
Business - East . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,595,533
Business - West/Services/Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
109,021
23,509
23,359
—
—
—
—
—
—
Total Load . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,876,746
23,509
23,359
12
Year ended December 31,
2020
2019
2021
Customer count - Electricity customers(a)(b) (in thousands)
Home - Texas
Average retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ending retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Home - East
Average retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ending retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Home - West/Services/Other
Average retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ending retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Customer count - Natural gas customers(b) (in thousands)
Home - East
Average retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ending retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Home - West/Services/Other
Average retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ending retail . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,055
3,024
1,484
1,402
510
498
360
364
452
434
2,449
2,451
1,019
970
—
—
156
166
—
—
2,358
2,450
990
1,070
—
—
122
158
—
—
Total Customer count
Average retail - Home . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ending retail - Home . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5,861
5,722
3,624
3,587
3,470
3,678
(a) Includes services customers
(b) Dual fuel customers are included within electricity customer counts only
The following are industry statistics for the Company's fossil and nuclear plants, as defined by the NERC:
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 by the station.
The tables below presents these performance metrics for the Company's generation portfolio, including leased facilities,
for the years ended December 31, 2021 and 2020:
Year Ended December 31, 2021
Fossil and Nuclear Plants (a)
Net Owned
Capacity (MW) (b)
Net Generation
(In thousands of
MWh) (a)
Annual Equivalent
Availability Factor
Average Net Heat
Rate BTU/kWh
Net Capacity
Factor
Texas . . . . . . . . . . . . . . . . . . . . . .
East . . . . . . . . . . . . . . . . . . . . . . . .
West/Services/Other . . . . . . . . . .
10,083
5,476
2,318
36,920
7,494
7,949
70.6 %
79.8 %
88.0 %
10,717
11,877
7,337
42.4 %
8.8 %
47.2 %
13
Year Ended December 31, 2020
Fossil and Nuclear Plants (a)
Net Owned
Capacity (MW)
Net Generation
(In thousands of
MWh) (a)
Annual Equivalent
Availability Factor
Average Net Heat
Rate BTU/kWh
Net Capacity
Factor
10,082
9,482
3,234
31,385
4,102
9,171
76.0 %
81.7 %
88.0 %
10,781
12,329
7,338
35.9 %
4.8 %
52.3 %
Texas . . . . . . . . . . . . . . . . . . . . . . .
East . . . . . . . . . . . . . . . . . . . . . . . .
West/Services/Other . . . . . . . . . . .
(a)
Excludes equity method investments
The generation performance by region for the three years ended December 31, 2021, 2020 and 2019 is shown below:
(In thousands of MWh)
Texas
Net Generation
2021
2020
2019
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear (a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
East
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total East (b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
West/Services/Other
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Renewables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total West/Services/Other (c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
18,876
8,846
9,198
36,920
5,774
201
1,519
7,494
7,941
8
7,949
15,701
6,006
9,678
31,385
1,888
322
1,892
4,102
9,165
6
9,171
21,985
6,315
9,695
37,995
4,435
209
2,269
6,913
9,450
12
9,462
Total generation performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
52,363
44,658
54,370
(a)
(b)
(c)
Reflects the Company's undivided interest in total MWh generated by STP
Includes gas generation of 855 thousand MWh, 870 thousand MWh and 903 thousand MWh and oil generation of 199 thousand MWh, 322 thousand
MWh and 209 thousand MWh for the years ended December 31, 2021, 2020 and 2019, respectively, that was sold to Generation Bridge
Includes gas generation of 2,445 thousand MWh, 3,002 thousand MWh, and 2,203 thousand MWh for the years ended December 31, 2021, 2020 and
2019, respectively, that was sold to Generation Bridge
Competition
While there has been consolidation in the competitive retail space over the past few years, there is still considerable
competition for customers. In Texas, there is healthy competition in deregulated areas and customers can choose providers
based on the most appealing offers. Outside of Texas, electricity retailers compete with the incumbent utilities, in addition to
other retail electric providers, which can inhibit competition depending on the market rules of the state. There is a high degree
of fragmentation, with both large and small competitors offering a range of value propositions, including value, rewards, and
sustainability-based offerings.
Wholesale generation is highly fragmented and diverse in terms of industry structure by region. As such, there is wide
variation in terms of the capabilities, resources, nature and identities of the Company’s competitors 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.
Seasonality and Price Volatility
The sale of power and natural gas to retail customers are seasonal businesses with the demand for power generally
peaking during the summer, and the demand for natural gas generally peaking during the winter. As a result, net working
capital requirements for the Company's retail operations generally increase during summer and winter months along with the
higher revenues, and then decline during off-peak months. Weather may impact operating results and extreme weather
conditions could have a material impact. The rates charged to retail customers may be impacted by fluctuations in total power
14
prices and market dynamics, such as the price of natural gas, transmission constraints, competitor actions, and changes in
market heat rates.
Annual and quarterly operating results of the Company's generation portfolio 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 regions in which the Company operates.
Market Framework
NRG sells electricity, natural gas and related products and services to customers throughout the U.S. and Canada. In most
of the states and regions that have introduced retail consumer choice, NRG competitively offers electricity, natural gas, portable
power and other value-enhancing services to customers. Each retail consumer choice state or province establishes its own retail
competition laws and regulations, and the specific operational, licensing, and compliance requirements vary by state or
province. 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. In Canada, NRG sells
energy and related services to residential and commercial customers in the province of Alberta pursuant both to a regulated rate
service governed by provincial regulations as well as a competitive service with rates set by market forces. Sales of energy to
commercial customers take place in other provinces as well. The attractiveness of NRG's retail offerings may be impacted by
the rules, regulations, market structure and communication requirements from public utility commissions in each state and
province.
NRG's fleet of power plants which it owns, operates or manages are located 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. 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 business in Texas is subject to standards and regulations adopted by the PUCT and ERCOT(a), including the
requirement for retailers to be certified by the PUCT in order to contract with end-users to sell electricity. 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 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, with subsequent amendments made in 2019, 2020 and 2021. The majority of the retail load in the
ERCOT market region is served by competitive retail suppliers, except certain areas that have not opted into competitive
consumer choice and are served by municipal utilities and electric cooperatives.
East
While most of the states in the East region of the U.S. have introduced some level of retail consumer choice for electricity
and/or natural gas, the incumbent utilities currently provide default service in most of the states and as a result typically serve
the majority of residential customers. NRG’s retail activities in the East are subject to standards and regulations adopted by the
ISOs, state public utility commissions and legislators, including the requirement for retailers to be certified in each state in order
to contract with end-users to sell electricity.
(a)
The Cottonwood facility is located in Deweyville, Texas, but operates in the MISO market
15
Power plants owned, operated and managed by NRG and NRG's demand response assets located in the East region of the
U.S. are within the control areas of PJM, NYISO and MISO. 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 assets in the East region
receive a significant portion of their revenues from capacity markets. PJM uses a forward capacity auction, while NYISO uses a
month-ahead capacity auction. MISO has an annual auction. Capacity market prices are sensitive to design parameters, as well
as additions of new capacity. PJM operates a pay-for-performance model where capacity payments are modified based on real-
time generator performance. In such markets, NRG’s actual capacity revenues will be the combination of cleared auction prices
times the quantity of MW cleared, plus the net of any over-performance "bonus payments" and any under-performance charges.
Additionally, bidding rules allow for the incorporation of a risk premium into generator bids.
West
In the West region of the U.S., NRG owns equity interests in natural gas-fired power plants 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.
Canada
In Canada, NRG sells to residential and commercial retail customers in Alberta under both regulated rates approved by the
AUC as well as through competitive service. The Company's regulated rates are approved through periodic rate applications
that establish rates for power and gas sales as well as for recovery of other costs associated with operating the regulated
business. In addition, the Company sells energy to commercial customers in other provinces. All sales and operations are
subject to applicable federal and provincial laws.
Regulatory Matters
As participants in wholesale and retail energy markets and owners and operators of power plants, 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 generation 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 and provinces 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
In March 2021, President Biden announced a framework for his "Build Back Better" initiative which includes policies to
address climate change across the whole of the federal government through the tax code, an energy efficiency and clean energy
incentives, research and development, among other areas of focus. The "Build Back Better" initiative has taken the form of two
separate bills in Congress. The $1.2 trillion "core infrastructure" bill, which contains spending on new electric vehicle charging
programs, among other things, was signed into law by President Biden on November 15, 2021. The remaining priorities,
commonly referred to as "Build Back Better," are being monitored by NRG as they progress through the legislative process.
State and Provincial Energy Regulation
Illinois Legislation — Illinois enacted the Climate and Equitable Jobs Act ("CEJA") on September 15, 2021, which
targets 100% clean energy by 2050. CEJA focuses on (i) decarbonization, (ii) incentives to transition coal plants into clean
energy facilities and (iii) nuclear subsidies. CEJA requires non-publicly owned coal or oil electric generating units larger than
25 MWs to eliminate CO2e and copollutant emissions by January 1, 2030. Non-publicly owned electric generating units that
are gas-fired, including Joliet, must eliminate CO2e and copollutant emissions, including through unit retirement or the use of
100% green hydrogen, in a timeframe ranging from January 1, 2030 to January 1, 2045 depending on certain emission rates and
proximity to environmental justice communities. Furthermore, CEJA placed restrictions, with immediate effect, on gas-fired
units that limits future emissions to their historic baselines. These limits affect the total potential energy production by gas units
in Illinois. PJM, the PJM Independent Market Monitor and the Illinois Environmental Protection Agency have exchanged
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correspondence to obtain clarification on the implications of these restrictions. The new energy law also provides $174 million
in incentives to develop solar and battery storage at coal generating sites that may be available to NRG.
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 24, Regulatory Matters, to the Consolidated Financial Statements.
Texas
Public Utility Commission of Texas’ Actions with Respect to Wholesale Pricing and Market Design — In September 2021,
the PUCT opened a rulemaking project to evaluate whether it should amend its rules to modify the High System Wide Offer
cap ("HCAP") and the ORDC, which is intended to ensure prices in the competitive market appropriately reflect the value of
operating reserves as the system approaches scarcity conditions. This rulemaking project concluded in December 2021,
resulting in a rule amendment that lowered the HCAP to $5,000 per MWh and which expands the minimum contingency level
to 3,000 MW. These two changes are broadly offsetting in their effect on overall average energy prices.
Activity on Securitization and ERCOT Pricing during Winter Storm Uri — The Texas Legislature acted to pass a variety
of securitization vehicles to finance exceptionally high power and gas costs from Winter Storm Uri, including HB 4492.
ERCOT subsequently filed two applications requesting the PUCT to issue Debt Obligation Orders ("DOOs") based on the
legislation. On October 13, 2021, the PUCT issued DOOs authorizing ERCOT's securitization of $800 million to cover short
payments and reimburse congestion revenue right account holders for amounts related to the default of market participants other
than electric cooperatives Brazos and Rayburn, which are discussed below (the "Default Securitization") and $2.1 billion
related to highly priced ancillary service and ORPDA during Winter Storm Uri (the "Uplift Securitization").
The DOOs require ERCOT to issue loans or securitized bonds through a bankruptcy remote special purpose entity as the
borrower and distribute the proceeds to affected market participants for default-related short payments and to LSEs for certain
ancillary-service and ORDPA costs using an allocation of proceeds based on an LSE's exposure to relevant costs as calculated
by the LSE's prevailing load-ratio share during the period of Winter Storm Uri, and a further redistribution of proceeds initially
allocated to other LSEs and customers who opt-out of securitization. In turn, ERCOT will charge non-bypassable fees related to
the Default Securitization and Uplift Securitization to all qualified scheduling entities and to all LSEs (other than those that
have opted-out), respectively. The Uplift Securitization provided for a one-time opt-out for certain LSEs or individual
transmission-level customers who in exchange for foregoing any securitization-related proceeds likewise avoid future fees
assessed by ERCOT for the use of repaying ERCOT's debt obligations. However, nearly all competitive REPs were required by
the law to participate, ensuring the charge established by the law is competitively neutral. These opt-outs and calculations of the
allocation of proceeds have been finalized. Based on LSE-level detail published by the PUCT on December 7, 2021, NRG will
receive $689 million of Uplift Securitization proceeds, with receipt expected to occur during the second quarter of 2022. The
$800 million Default Securitization was disbursed by ERCOT in November 2021, with NRG receiving $12 million.
Electric Cooperative Bankruptcy and Securitization — Of the defaults in the ERCOT market, two electric cooperatives,
Brazos and Rayburn, constitute the vast majority. Brazos currently is in bankruptcy. NRG and ERCOT have both filed a proof
of claim in the bankruptcy proceeding of Brazos, and Brazos has challenged ERCOT's claims in a manner that may prejudice
NRG's claims against Brazos. During the fourth quarter of 2021, ERCOT filed a motion to dismiss Brazos' complaint relating to
ERCOT's proof of claim, which NRG joined in support, but this motion was denied by the Bankruptcy Court, and ERCOT,
NRG and certain other parties appealed. On January 11, 2022, the United States District Court for the Southern District of
Texas entered an order allowing the appellants to seek direct review from the Fifth Circuit Court of Appeals of the Bankruptcy
Court's decision on the motion to dismiss. On January 18, 2022, ERCOT, NRG and certain other parties filed a petition for
direct review by the United States Court of Appeals for the Fifth Circuit. The Court of Appeals granted the petition on February
4, 2022. On February 7, 2022, the Bankruptcy Court entered an order granting summary judgement in favor of Brazos on
whether ERCOT's sales to Brazos were in the ordinary course of Brazos' business. The Bankruptcy Court ruled that the portion
of ERCOT's claims for charges incurred by Brazos after the intervention of the PUCT and ERCOT were not in the ordinary
course and thus are not entitled to administrative expense status under the Bankruptcy Code. The amount and priority of
ERCOT's claim for amounts incurred prior to such intervention or after such intervention ceased are issues to be determined at
trial. The Bankruptcy Court's summary judgement ruling may also apply to NRG's claims again Brazos. Trial on the merits of
the ERCOT proof of claim and Brazos' complaint is set to commence before the Bankruptcy Court on February 22, 2022. To
the extent the Bankruptcy Court reduces or disallows claims against Brazos, this presents risk for NRG.
ERCOT's market protocols provide for short payments to be extinguished through a process of uplift, whereby the cost of
defaults is allocated to all market participants, including retailers, generators, municipal and cooperative utilities, and financial
traders. However, the total amount of this uplift is limited by ERCOT's current protocols of $2.5 million per month.
Consequently, it would take approximately 63 years for the net short-pay balance of $1.887 billion related to Brazos to be
uplifted to the market under the current market rules. NRG's undiscounted share of the uplift based on its current market share
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is estimated to be approximately $121 million and has been short-paid $68 million. The remaining $53 million has been
discounted based on the 63 year repayment term and present value of $9 million was recorded as an additional liability.
Rayburn announced that it intended to securitize the amounts owed to ERCOT and payment from such securitization is
expected in the first quarter of 2022.
Reliability and Plant Operations Standards — The PUCT established a rulemaking to establish weatherization standards,
and issued a notice for comments in response to provisions of Texas Senate Bill 3 ("SB3") that require mandatory standards for
power generators and others within the electric-power sector. SB3 provides that the standards adopted by the PUCT be
implemented by generation owners, be subject to ERCOT inspections, and that ERCOT provide asset owners with a reasonable
period of time to remedy any violation. Continuing violations would be subject to an administrative penalty and a requirement
that a third-party contractor assess the asset owner's weatherization plans. On August 24, 2021, Commission Staff issued a
proposal of weatherization standards for publication. NRG, through its trade association, filed comments. On October 21, 2021,
Commissioners of the PUCT voted to adopt the rule without substantial modifications from the proposal.
PJM
PJM’s Variable Resource Requirement Curve — On July 9, 2021, the Court of Appeals for the D.C. Circuit issued a
decision denying in part and granting in part an appeal by several PJM state consumer advocates regarding FERC’s order
approving revisions to PJM’s Variable Resource Requirement Curve (“VRR”). The court upheld PJM's use of a greenfield gas-
fired combustion turbine as the reference unit to establish Net Cost of New Entry ("Net CONE"). However, the court remanded
back to FERC the issue of allowing generators to have a 10% adder to their offer to supply capacity in the PJM market, and on
January 20, 2022, FERC issued an order removing the 10% adder. The VRR is the demand curve that represents the slope of
bids in the auction that ultimately results in the price and quantity of capacity allocated to load-serving entities, including NRG.
The VRR curve is based on several inputs, including the Net CONE. The outcome could affect PJM’s capacity market prices.
PJM Revisions to Minimum Offer Price Rule — On July 30, 2021, PJM filed proposed tariff changes at FERC to largely
eliminate the current minimum offer price rules ("MOPR") except in very narrow cases. The proposal would eliminate: (i) the
current MOPR for new entrant natural gas resources effective with the 2023/2024 delivery year and (ii) the expanded MOPR
established in FERC's December 2019 Order to address out-of-market subsidies. On September 30, 2021, PJM's proposal went
into effect by operation of law because the FERC Commissioners were split 2-2 as to the lawfulness of the change. Multiple
parties filed motions for rehearing and ultimately appealed to the federal court of appeals. On December 21, 2021 and
December 30, 2021, respectively, the Third Circuit Court of Appeals and the Seventh Circuit Court of Appeals issued an order
holding the appeals in abeyance. The proposed revisions would allow PJM to address specific and narrow instances of buyer-
side market power through subsequent filings at FERC. Any changes to the PJM capacity market construct may impact the
outcome of future Base Residual Auctions.
PJM's ORDC Filing and Compliance Directives — On May 21, 2020, PJM proposed energy and reserve market reforms
to enhance price formation in reserve markets, which included modifying ORDC and aligning market-based reserve products in
Day-Ahead and Real-Time markets. In addition to approving PJM's proposal, FERC also directed PJM to implement a forward-
looking Energy and Ancillary Services Offset to be used in PJM's capacity markets. After multiple compliance filings, parties
filed appeals at the Court of Appeals for the D.C. Circuit of FERC’s orders, and on August 13, 2021, FERC filed a motion and
was granted a voluntary remand the case back to the agency. On December 22, 2021, FERC issued its order on voluntary
remand affirming in part and reversing in part FERC's determination. Specifically, FERC reversed itself and ordered PJM to: (i)
eliminate the more robust ORDC curves and reserve penalty adders and maintain the existing (lower) curves and (lower)
penalty adders and (ii) restore its tariff provisions related to its prior backward-looking Energy and Ancillary Services Offset.
At the direction of FERC, on January 21, 2022, PJM filed a compliance fling proposing a new schedule for the Base Residual
Auctions.
Independent Market Monitor Market Seller Offer Cap Complaint — On March 18, 2021, finding that the calculation of
the default Market Seller Offer Cap was unjust and unreasonable, the Order permitted the current PJM May 2021 capacity
auction for the 2022/2023 delivery rule to continue under the existing rules and set a procedural schedule for parties to file
briefs with possible solutions. On September 2, 2021, FERC issued an order in response to a complaint filed by the PJM
Independent Market Monitor's proposal, which eliminates the Cost of New Entry-based Market Seller Offer Cap and
implements a limited default cap for certain asset classes based on going-forward costs and provides for unit specific cost
review by the Independent Market Monitor for all other non-zero offers into the auctions. As required by the Order, PJM
submitted its compliance tariff on October 4, 2021. On October 4, certain parties filed a motion for rehearing. which was
denied. Multiple parties filed appeals at the Court of Appeals for the D.C. Circuit. The appeals are currently being held in
abeyance. The removal of the Offer Caps may impact the outcome of future Base Residual Auctions.
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New York
NYISO's Revisions to the Buyer Side Mitigation Rules — On January 5, 2022, the NYISO filed its Comprehensive
Mitigation Review proposing changes to the buyer-side mitigation rules. The proposal would remove certain facilities to be
reviewed under the buyer-side mitigation rules to serve the goals of New York's Climate Leadership and Community Protection
Act, adopt a marginal capacity accreditation market design and adjust the rules surrounding installed and unforced capacity.
Changes to NYISO's Buyer Side Mitigation rules may impact the outcome of future capacity auctions.
California
California Resource Adequacy Proceedings — On March 25, 2021, the CPUC directed the state's major investor-owned
utilities to engage in up to 1.5 GW of emergency procurement for 2021 and 2022 and is currently evaluating further
procurement directives through 2023. In the same docket, the CPUC approved a new demand response program for use during
emergency conditions. As part of the Integrated Resource Procurement docket, the CPUC approved a decision on June 24, 2021
that will require all Load Serving Entities to procure a pro rata share of 11.5 GW of new non-fossil resource adequacy from
2023 to 2026. To replace the retiring Diablo Canyon nuclear plant, this will consist largely of GHG-free energy, long-duration
storage, baseload renewables and energy storage. A new resource adequacy docket opened in October 2021 will consider
changes to the reserve margin and qualifying capacity of different resource types, and the CPUC and CAISO will continue to
evaluate major structural reforms to the resource adequacy program in California that would begin in 2024.
Midway-Sunset Reliability Must Run Proceeding — San Joaquin Energy, LLC, a subsidiary of NRG, owns a 50%, non-
controlling interest in the Midway-Sunset Cogeneration Company ("MSCC"). MSCC owns a cogeneration facility near
Fellows, California and submitted mothball notices for the cogeneration facility to the CAISO in the latter half of 2020. On
December 17, 2020, the CAISO Board effectively rejected the mothball notices by authorizing its staff to designate the MSCC
facility as a reliability must-run ("RMR") resource conditioned on execution of a RMR contract. On January 29, 2021, MSCC
made its RMR filing at FERC. Multiple parties filed protests and on March 16, 2021, MSCC filed a response to those protests.
On April 2, 2021, FERC accepted the RMR filing, suspended it to become effective February 1, 2021 subject to refund and
established hearing and settlement judge proceedings. The parties are engaging in settlement proceedings. On September 27,
2021, the CAISO gave notice to MSCC extending the term of the reliability designation through December 31, 2022.
Canada
Alberta Energy Market — In December 2020, prior to its acquisition by NRG, Direct Energy filed a Non-Energy Rate
Application with the AUC to approve cost recovery for the 2020-2022 period. Major cost elements of this application relate to
bad debt, corporate costs, and customer care and billing contracts. The Company engaged in a mediation and settlement
process, and on April 20, 2021 an all-party settlement was executed, and was filed with the AUC on April 23, 2021. The AUC
approved the settlement agreement on June 4, 2021. Separately, the Company received approval from the AUC of a negotiated
rate settlement for its electricity focused 2020-2022 Energy Price Setting Plan which went into effect on July 1, 2021. The
Company has completed the last repayment to the Balancing Pool and the Alberta government as part of its 90-day utility bill
deferral program. This program, effective March 18, 2020, was designed to assist residential, farms, and small business
customers who were negatively affected by COVID-19 related economic circumstances by temporarily deferring their utility
bill payments. The program was also designed to mitigate bad debt risks associated with the implementation of the program.
Environmental Regulatory Matters
NRG is subject to numerous environmental laws in the development, construction, ownership and operation of power
plants. These laws generally require that governmental permits and approvals be obtained before construction and maintained
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 the
Company's operations. Complying with environmental laws often involves specialized human resources and 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 affect the Company have been revised recently by the EPA, including ash storage and
disposal requirements, NAAQS revisions and implementation and effluent limitation guidelines. Some of these recent revisions
may, in turn, be revised by the current U.S. presidential administration. 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.
Air
The CAA and related 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
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classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS may 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.
CPP/ACE Rules — The attention in recent years on GHG emissions has resulted in federal and state regulations. In
October 2015, the EPA promulgated the CPP, addressing GHG emissions from existing EGUs. On February 9, 2016, the U.S.
Supreme Court stayed the CPP. In July 2019, EPA promulgated the ACE rule, which rescinded the CPP, which had sought to
broadly regulate CO2 emissions from the power sector. On January 19, 2021, the D.C. Circuit vacated the ACE rule (but on
February 22, 2021, at the EPA's request, stayed the issuance of the portion of the mandate that would vacate the repeal of the
CPP). On October 29, 2021, the U.S. Supreme Court agreed to review the D.C. Circuit's decision, which should provide some
clarity regarding the scope of the EPA's authority to regulate CO2 under the Clean Air Act. The Company expects the EPA to
promulgate a new rule to regulate GHG emissions from power plants after a decision from the U.S. Supreme Court.
Greenhouse Gas Emissions — NRG emits CO2 (and small quantities of other GHGs) when generating electricity at a
majority of its facilities. Nearly all (>99%) of NRG's domestic GHG emissions are subject to federal (U.S. EPA) GHG
reporting requirements.
NRG's climate goals are to reduce greenhouse gas emissions by 50% by 2025, from its current 2014 baseline, and to
achieve net-zero emissions by 2050. Greenhouse gas emissions include directly controlled emissions, emissions from NRG's
purchased energy, and emissions from employee business travel. In 2021, NRG's climate goals were certified by the Science
Based Targets initiative as aligned with a 1.5 degree Celsius trajectory. From the current 2014 baseline to 2021, the Company's
CO2e emissions decreased from 61 million metric tons to 34 million metric tons, representing a cumulative 44% reduction. The
decrease is attributed to reductions in fleet-wide annual net generation and a market-driven shift away from coal as a primary
fuel to natural gas. The increase in emissions in 2021, as compared to 2020, was primarily due to higher power demand which
was a result of the easing of COVID-19 pandemic lockdowns and the associated economic recovery. The Company is
continuing to target a 50% reduction by 2025 and is on track to meet that goal.
As of December 31, 2021, less than 5% of the Company's consolidated operating revenues were derived from coal-fired
operating assets.
The following charts reflect the Company’s domestic generation portfolio, including leased facilities and those accounted
for through equity method investments. Prior year information was adjusted to remove divested assets.
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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
amended 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.
In 2019 and 2020, the EPA proposed several changes to this rule. On August 28, 2020, the EPA finalized "A Holistic Approach
to Closure Part A: Deadline to Initiate Closure," which amended the April 2015 Rule to address the August 2018 D.C. Circuit
decision and extend some of the deadlines. On November 12, 2020, the EPA finalized "A Holistic Approach to Closure Part B:
Alternative Demonstration for Unlined Surface Impoundments," which further amended the April 2015 Rule to, among other
things, provide procedures for requesting approval to operate existing ash impoundments with an alternate liner.
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, Commitments and Contingencies, to the Consolidated Financial Statements.
Jewett Mine Lignite Contract — The Company's Limestone facility historically burned lignite obtained from the Jewett
mine, which was operated by TWCC. In 2019, the Jewett mine and related lignite supply agreement with NRG were acquired
by Westmoreland Jewett Mining LLC ("Jewett Mining"), a subsidiary of Westmoreland Mining LLC pursuant to a plan of
reorganization confirmed by the Texas Bankruptcy Court. Effective August 5, 2020, NRG's subsidiary, NRG Texas LLC,
acquired all of the equity interests of Jewett Mining. Active mining under the lignite supply agreement ceased as of December
31, 2016; however, under the terms of the lignite supply agreement, Jewett Mining remains responsible for reclamation
activities and NRG is responsible for all reclamation costs. NRG has recorded an adequate ARO liability. The Railroad
Commission of Texas has imposed a bond obligation of approximately $99 million for the reclamation of the Jewett mine,
which NRG supports through surety bonds. The cost of the reclamation may exceed the value of the bonds. NRG may provide
additional performance assurance if required by the Railroad Commission of Texas.
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.
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 has
been extended three times through addendums to cover payments through December 31, 2022. 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 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 in 1985, 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. Texas is currently in a compact with the state of Vermont, and the compact low-level waste facility located in
Andrews County in Texas has been operational since 2012.
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.
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Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines ("ELG") for
Steam Electric Generating Facilities, which imposed more stringent requirements (as individual permits were renewed) for
wastewater streams from FGD, fly ash, bottom ash, and flue gas mercury control. On September 18, 2017, the EPA
promulgated a final rule that, among other things, postponed 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 amended the rule. On October 13,
2020, the EPA amended the 2015 ELG rule by: (i) altering the stringency of certain limits for FGD wastewater; (ii) relaxing the
zero-discharge requirement for bottom ash transport water; and (iii) changing several deadlines. On July 26, 2021, the EPA
announced that it is initiating a new rulemaking to evaluate revising the ELG rule. While the EPA is developing the new rule,
the existing rule (as amended in 2020) will stay in place, and the EPA expects permitting authorities to continue to implement
the current regulation. The EPA anticipates releasing a proposed rule in fall 2022. In October 2021, NRG informed its
regulators that the Company intends to comply with the ELG by ceasing combustion of coal by the end of 2028 at its domestic
coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants in Texas.
Regional Environmental Developments
Ash Regulation in Illinois — On July 30, 2019, Illinois enacted legislation that requires the state to promulgate regulations
regarding coal ash at surface impoundments. On April 15, 2021, the state promulgated the implementing regulation, which
became effective on April 21, 2021. The new regulation requires NRG to apply for initial operating permits for its coal ash
surface impoundments by October 31, 2021 and construction permits (for closure) starting in 2022.
Customers
NRG sells to a wide variety of customers, primarily end-use customers in the residential, commercial and industrial
sectors. The Company owns and operates power plants to generate and sell power to wholesale customers, such as utilities and
other intermediaries. The Company had no customer that comprised more than 10% of the Company's consolidated revenues
for the year ended December 31, 2021.
Human Capital
As of December 31, 2021, NRG and its consolidated subsidiaries had 6,635 employees, approximately 13% of whom
were covered by U.S. collective bargaining agreements. During 2021, the Company did not experience any labor stoppages or
labor disputes at any of its facilities.
NRG believes its employees are vital to its success and is committed to offering employees a rewarding career that
provides opportunities for growth and the ability to make valuable contributions toward the achievement of the Company’s
business objectives. NRG focuses on safety, health and wellness, diversity, equity and inclusion, talent development and total
rewards for its employees.
Safety
Safety is embedded in the culture at NRG. The Company strives to begin each meeting with a safety moment and
regularly reminds its employees that safety comes first. NRG has achieved its targeted top decile safety record of Occupational
Safety and Health Administration recordable injury rates in each of the 5 previous years.
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Health and Wellness
For several years, NRG has invested in the well-being of its employees and their families. NRG provides programs that
holistically support its employees’ physical, emotional and financial wellness, allowing employees the opportunity to take
control of their well-being and focus on what matters most to them for a healthy, secure future.
During 2020, the Company evaluated its approach to health and well-being in light of the circumstances resulting from the
COVID-19 pandemic. In response to COVID-19, NRG implemented additional programs to provide services to support the
needs of employees, including those working from home, such as programs that provided back-up childcare, expanded access to
telemedicine (for both physical and mental health), and supported mental and emotional well-being through programs such as
mindfulness. During 2021, the Company continued its support of employees by partnering with the National Council for
Behavioral Health to roll out their Mental Health First Aid program. This program safely, respectfully and effectively opens the
conversation about mental illness and addiction, encourages employees to recognize and take responsibility for their mental
health, teaches managers to recognize and speak to an employee with a mental health concern before it creates performance
problems, complements and supports existing benefit and wellness programs and company’s policies and procedures.
Diversity, Equity and Inclusion
NRG is committed to diversity, equity and inclusion ("DE&I") as an integral part of the Company. In 2020, NRG
completed a gender and race pay equity study to ensure that the Company's pay decisions were not influenced by gender, race,
or other similar factors. The study showed equitable pay practices after accounting for education, experience, performance and
location. NRG also conducted company-wide unconscious bias training to help all employees recognize, understand, and reduce
implicit bias and offers various other related guides and tools to its employees and management.
In 2021, the Company focused on embedding DE&I in the Company’s operations, culture and communications, by
working with diverse suppliers, finding diverse talent, facilitating engagement and awareness of DE&I by employees, and
committing to be accountable for our DE&I progress.
Talent Development
NRG deploys various talent development strategies and programs with the goal of ensuring a pipeline of leadership who
can execute on the Company’s strategy and drive value for all stakeholders. The Board of Directors regularly engages with
management on leadership development and succession planning, including providing feedback on development plans and
bench strength for key senior leader positions. The Board of Directors also has a structured program that allows directors to
interact directly with individuals deeper within the organization whom management, through a robust talent assessment
program, as well as mentoring relationships, has identified as high potential future leaders. In 2021, the Company launched an
Executive Leadership Program to strengthen the identified pipeline of future leaders and create a cohort of high potential
candidates for the program. The Company has a performance management tool that emphasizes a continuous feedback loop and
a robust online training curriculum with topics including leadership, communication and productivity.
Total Rewards
NRG seeks to provide the median target of compensation and benefits, benchmarked against direct peers, industry, and,
where appropriate, general peers. To ensure incentives are properly aligned with business needs and can attract and retain
qualified employees, the Compensation Committee of the Board of Directors actively reviews the Company's total rewards
programs, including benchmarking programs against peer groups, assessing the risks of programs and evaluating the design of
the annual and long-term incentive programs. The Company offers full-time employees incentives designed to motivate and
reward success. NRG continues to evaluate its offerings taking into consideration the needs of its employees to ensure they are
competitive and best serve its employees. Every two years, the Company engages an independent third party to benchmark its
compensation and benefits programs against its peers and report the results to the Compensation Committee of the Board of
Directors.
For further discussion and recent available data regarding the Company’s efforts and programs please see the Company’s
2021 Proxy Statement and 2020 Sustainability Report, which are available on the Company’s website at: www.nrg.com.
Information included in these documents is not intended to be incorporated into this Form 10-K.
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
SEC's website, www.sec.gov, and 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
NRG's risk factors are grouped into the following categories: (i) Risks Related to the Acquisition of Direct Energy; (ii)
Risks Related to the Operation of NRG's Business; (iii) Risks Related to Governmental Regulation and Laws; (iv) Risks
Related to Public Health Threats; and (v) Risks Related to Economic and Financial Market Conditions, and the Company's
Indebtedness.
Risks Related to the Acquisition of Direct Energy
The acquisition of Direct Energy may not achieve its intended results.
Achieving the anticipated benefits of cost savings and operating efficiencies of the acquisition is subject to a number of
uncertainties, including whether the businesses of NRG and Direct Energy are integrated in an efficient and effective manner.
Failure to achieve these anticipated benefits could result in increased costs, lower-than-expected revenues or income generated
by the combined company and diversion of management's time and energy, which could have an adverse effect on the
Company's business, financial results and prospects.
The Company will be subject to business uncertainties related to Direct Energy that could adversely affect its financial
results.
Uncertainty about the effects of the acquisition of Direct Energy on employees, customers and suppliers may have an
adverse effect on NRG's business. Although the Company intends to take steps designed to reduce any adverse effects, these
uncertainties may impair its ability to attract, retain and motivate key personnel for a period of time, and could cause customers,
suppliers and others that deal with it to seek to change existing business relationships.
Employee retention and recruitment may be particularly challenging, as employees and prospective employees may
experience uncertainty about their future roles with the Company. If, despite the Company's retention and recruiting efforts, key
employees depart or fail to accept employment with NRG because of issues relating to the uncertainty and difficulty of
integration or a desire not to remain with NRG, the Company's financial results could be affected.
The integration of NRG and Direct Energy may disrupt or have a negative impact on the Company’s business.
The acquisition of Direct Energy is complex, and the Company will devote significant time and resources to integrating its
operations with the operations of NRG. NRG could have difficulty integrating the acquired assets and personnel of Direct
Energy with its own. The integration of NRG and Direct Energy may place a significant burden on management and internal
resources. The diversion of management attention away from ongoing business concerns and any difficulties encountered in the
transition and integration process could affect the Company's business, results of operations and financial condition. Risks that
could impact the Company negatively include:
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the difficulty of managing and integrating Direct Energy and its operations;
the potential disruption of the ongoing businesses and distraction of management;
changes in our business focus and/or management;
difficulties in implementing and maintaining uniform processes, systems, standards, controls, procedures, practices,
policies and compensation standards;
unanticipated issues in integrating information technology, communications, and other systems;
the possibility of faulty assumptions underlying expectations regarding the integration process;
the potential impairment of relationships with employees and partners;
unforeseen expenses associated with the acquisition of Direct Energy, including delays to the integration of Direct
Energy’s business as a result of the COVID-19 pandemic;
the potential difficulty in managing an increased number of locations and employees;
the potential loss of valuable employees;
difficulty addressing any possible differences in corporate cultures and management philosophies;
unanticipated changes in federal or state laws or regulations; and
the effect of any government regulations that relate to the business acquired.
If the Company is not successful in addressing these risks effectively, the business could be impacted. Many of these
factors will be outside of the Company’s control, and any one of them could result in delays, increased costs, decreases in the
amount of expected revenues and diversion of management’s time and energy, which could materially affect NRG’s business,
results of operations and financial condition.
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Risks Related to the Operation of NRG's Business
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 and gas prices may also fluctuate
substantially due to other factors outside of the Company's control, including:
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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, retirement of existing plants or addition of new transmission capacity;
environmental regulations and legislation;
electric supply disruptions, including plant outages and transmission disruptions;
changes in power and gas transmission infrastructure;
fuel price volatility and 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 gas, or in patterns of power or gas 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;
economic and political conditions;
federal, state and provincial power regulations and legislation, and regulations and actions of the ISO and RTOs;
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 and other changes to costs, the Company may not be able to pass through all such changes to customers. For
example, serving retail power customers in ISOs that have a capacity market exposes the Company to the risk that capacity
costs can change and may not be recoverable, or the Company may engage in 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 impacted by regulatory rules.
Further, in low natural gas price environments, natural gas can be the more cost-competitive fuel compared to coal for
generating electricity. 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.
Such factors and the associated fluctuations in power prices have affected the Company's wholesale and retail profitability
in the past and are expected to continue to do so in the future.
Volatile power and gas supply costs and demand for power and gas could adversely affect the financial performance of
NRG's retail operations.
NRG's retail power operations purchase a significant portion of their supply from third parties. All of the gas sold by the
Company in retail and wholesale markets is purchased from third parties. As a result, financial performance depends on the
ability to obtain adequate supplies of power and gas from third parties at prices below the prices NRG charges its customers.
Consequently, the Company's earnings and cash flows could be adversely affected in any period in which the wholesale power
or gas prices rise at a greater rate than the rates the Company can charge to customers. The price of wholesale electricity and
gas supply purchases associated with the retail operations' energy commitments can be different than that reflected in the rates
charged to customers due to, among other factors:
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varying supply procurement contracts used and the timing of entering into related contracts;
subsequent changes in the overall price of natural gas;
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daily, monthly or seasonal fluctuations in the price of natural gas relative to the 12-month forward prices;
transmission and transportation constraints and the Company's ability to move power or gas to its customers; and
changes in market heat rate (i.e., the relationship between power and natural gas prices).
The Company's earnings and cash flows could also be adversely affected in any period in which its customers' actual
usage of electricity or gas significantly varies from the forecasted usage, which could occur due to, among other factors,
weather events, changes in usage patterns, competition and economic conditions.
Substantially all of NRG's businesses operates, wholly or partially, without long-term power sale agreements.
Many of NRG’s retail 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
addition, many of NRG’s generation facilities are exposed to market risk because they operate as "merchant" facilities without
long-term power sales agreements for some or all of their generating capacity and output. 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, plants 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.
Competition 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. The
Company's retail operations specifically face competition for customers. Competitors may offer different products, lower
prices, and other incentives which may attract customers away from the Company. 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 may face competition from 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.
The Company’s plant operations face competition from newer or more efficient plants owned by competitors, which may
put some of the Company's plants at a disadvantage to the extent these competitors are able to consume the same or less fuel as
the Company's plant. Over time, the Company's plants may be unable to compete with these more efficient plants, which could
result in retirements.
NRG’s competitors 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.
NRG's competitors may be able to respond more quickly to new laws or regulations or emerging technologies, or devote
greater resources to marketing of retail energy 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.
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. Grid operations depend on the
continuing financial viability of contractual counterparties, as well as 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 generation 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, if a
counterparty fails to perform or if there is a disruption in the fuel delivery infrastructure.
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.
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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.
NRG also buys significant quantities of energy 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.
NRG's plant operating characteristics and equipment, particularly at its coal-fired plants, often dictate the specific fuel
quality to be combusted. The availability and price of specific fuel qualities may vary due to supplier financial or operational
disruptions, transportation disruptions and force majeure. At times, coal of specific quality may not be available at any price or
the Company may not be able to transport such coal to its facilities on a timely basis. In this case, the Company may not be able
to run the coal facility even if it would be profitable. Operating a coal facility with different quality coal can lead to emission or
operating problems. If the Company had sold forward the power from such a coal facility, it could be required to supply or
purchase power from alternate sources, perhaps at a loss. This could have a material adverse impact on the financial results of
specific plants and on the Company's results of operations.
There may be periods when NRG will not be able to meet its commitments under forward sale 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 the Company's
forward sale 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, and NRG's hedging activities may increase the volatility in the Company's quarterly and annual financial
results.
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 business. 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 or gas forward, it gives up the opportunity to buy or sell 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.
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
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cash flow hedge accounting treatment or a scope exception. As a result, the Company's quarterly and annual results are subject
to significant fluctuations caused by changes in market prices.
NRG may not have sufficient liquidity to hedge market risks effectively.
The Company is exposed to market risks through its retail and wholesale operations, which involve the purchase of
electricity and natural gas 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 market 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 retail customers use more power or gas than expected, or if any of NRG's facilities experience unplanned
outages, the Company may be required to procure additional power or gas 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.
NRG relies on storage, transportation assets and suppliers, which it does not own or control, to deliver natural gas.
The Company depends on natural gas pipelines and other transportation and storage facilities owned and operated by third
parties to deliver natural gas to wholesale and retail markets and to provide retail energy services to customers. The Company's
ability to provide natural gas for its present and projected customers will depend upon its suppliers' ability to obtain and deliver
supplies of natural gas, as well as NRG's ability to acquire supplies directly from new sources. Factors beyond the control of the
Company and its suppliers may affect the Company's ability to deliver such supplies. These factors include other parties' control
over the drilling of new wells and the facilities to transport natural gas to the Company's receipt points, development of
additional interstate pipeline infrastructure, availability of supply sources competition for the acquisition of natural gas, priority
allocations, impact of severe weather disruptions to natural gas supplies and the regulatory and pricing policies of federal and
state regulatory agencies, as well as the availability of Canadian reserves for export to the U.S. Energy deregulation legislation
may increase competition among natural gas utilities and impact the quantities of natural gas requirements needed for sales
service. If supply, transportation or storage is disrupted, including for reasons of force majeure, the ability of the Company to
sell and deliver its products and services may be hindered. As a result, the Company may be responsible for damages incurred
by its customers, such as the additional cost of acquiring alternative supply at then-current market rates. These conditions could
have a material impact on the Company's financial condition, results of operations and cash flows.
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 products 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 incurring non-performance penalties and/or require NRG to incur
significant costs as a result of obtaining replacement power from third parties in the open market or running one of its higher
cost units 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.
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
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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, obtains warranties from vendors and
obligates contractors to meet certain performance levels, but the Company cannot provide any assurance that these measures
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 or protected 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.
Supplier and/or customer concentration 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.
The Company may also hedge a portion of its exposure to power and fuel price fluctuations through various physical or
financial agreements with counterparties. Counterparties to these agreements may breach or may be unable to perform their
obligations, and in case of renewable generation, such counterparties may be subject to additional risks, such as facility
development and transmission risks, unfavorable weather and atmospheric conditions, and mechanical or operational failures.
NRG may not be able to enter into replacement agreements on terms as favorable as its existing agreements, or at all. If the
Company is unable to enter into replacement purchase agreements or other replacement hedging agreements, the Company
would be exposed 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.
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.
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.
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.
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 power to its customers.
If transmission or distribution is disrupted, including by force majeure events, or if the transmission or distribution
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infrastructure is inadequate, NRG's ability to deliver 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 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.
Rates and terms for service of certain residential and commercial customers in Alberta are subject to regulatory review and
approval.
The Company owns Direct Energy Regulated Services, which serves as a regulated rate supplier for residential and
commercial energy customers in portions of the province of Alberta. It is required to engage in regulatory approval proceedings
as a part of the process of establishing the terms and rates for sales of power and natural gas. These proceedings typically
involve multiple parties, including governmental bodies and officials, consumer advocacy groups and various consumers of
energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates.
Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The
potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be
sufficient for the Company to recover its costs by the time the rates become effective. Established rates are also subject to
subsequent reviews by regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed. In
certain instances, the Company could agree to negotiated settlements related to various rate matters and other cost recovery
elements. These settlements are subject to regulatory approval. The ultimate outcome and timing of regulatory rate proceedings
have a significant effect on the Company to recover its costs or earn an adequate return. In addition, subsequent legislative or
regulatory action could alter the terms on which the regulated business operates and future earnings could be negatively
impacted. The Company also operates a competitive energy supply business in Alberta that is not subject to rate regulation and
is subject to stringent requirements to segregate operations and information relating to the competitive business from the
regulated business. Failure to comply with these and other requirements on the business could subject the Company's regulated
and competitive businesses in Alberta to fines, penalties, and restrictions on the ability to continue business.
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 or other attributes necessary to operate these projects optimally.
The approval of co-venturers also may be required for NRG to receive distributions of funds from projects or to transfer the
Company's interest in projects.
NRG may be unable to integrate the operations of acquired entities in the manner expected.
NRG enters into acquisitions that result in various benefits, including, among other things, cost savings and operating
efficiencies. Achieving the anticipated benefits of these acquisitions depends on whether the businesses can be integrated into
NRG in an efficient and effective manner. The integration process could take longer than anticipated and could result in the loss
of valuable employees, the disruption of NRG's businesses, processes and systems or inconsistencies in standards, controls,
procedures, practices, policies and compensation arrangements, any of which could divert the attention of management and
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 acquire or dispose 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
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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. 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.
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, data breaches 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 such activities, all of which 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. 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 or gas transmission and distribution
facilities upon which the Company is dependent, which may reduce retail volume for extended periods of time. Power or gas
supply may be sold at a loss if these events cause a significant loss of retail customer demand.
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. Hostile
cyber intrusions, including those targeting information systems, as well as electronic control systems used at the generation
facilities 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. 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, are 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.
In addition, the Company requires access to sensitive data in the ordinary course of business. Examples of sensitive 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 provides sensitive data to vendors and service providers, who require access to this information in order to provide
services to NRG, such as call center operations. If a significant breach occurs or if sensitive data that was entrusted to the
Company were mishandled, the reputation of NRG and its businesses may be adversely affected, customer confidence may be
diminished, or NRG and its retail operations 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.
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. 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 home back-up generators
and residential HVAC system repairs, installation and replacements. Where such work is performed by independent contractors,
such as repairs performed under the Company's home warranty and protection plan products, the Company may nonetheless
face claims and costs for damage. In addition, shortages of skilled labor for Company projects could significantly delay a
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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.
Changes in technology may impair the value of NRG's power plants and the attractiveness of its retail products, and 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.
Research and development activities are ongoing in the industry to provide alternative and more efficient technologies to
produce power, including wind, photovoltaic (solar) cells, hydrogen, 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.
Some emerging technologies, such as 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.
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, 2021, approximately 13% of NRG's employees 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.
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, or changes to,
the requirements under these legal regimes may cause the Company to incur significant additional costs, reduce the Company's
ability to hedge exposure or 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 and home warranty services are regulated on a state-by-
state or at the province-by-province level and are highly dependent on state and provincial 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.
Public utilities under the FPA are required to obtain FERC acceptance of their rate schedules for wholesale sales of
electricity. Except for ERCOT generation 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-
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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. 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 interference in the competitive wholesale marketplace.
NRG’s generation and competitive retail operations rely on a competitive wholesale marketplace. The competitive
wholesale marketplace may be impacted by out-of-market subsidies, 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
operations 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 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.
PJM operates 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.
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
33
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. 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 23, 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, and
policies at the national, regional and state levels to regulate GHG emissions and mitigate climate change could adversely
impact NRG's results of operations, financial condition and cash flows.
Fluctuations in weather and other environmental conditions, including temperature and precipitation levels, may affect
consumer demand for electricity or natural gas. 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
it to incur significant costs in preparing for or responding to these effects. These or other changes in climate could lead to
increased operating costs or capital expenses. NRG's 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.
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, transportation and delivery, 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.
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.
Further, 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.
NRG's GHG emissions for 2021 can be found in Item 1, Business —Environmental Regulatory Matters. GHG regulation,
at the state or federal level, could increase the cost of electricity generated by fossil fuels, and such increases could reduce
demand for the power NRG generates and markets. Any increase in costs at a national, regional or state level could adversely
affect NRG’s results of operations, financial condition and cash flows
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Changes in data privacy and data protection laws and regulations or any non-compliance with such laws and regulations,
could adversely affect NRG’s business and financial results.
The consumer privacy landscape continues to experience momentum for greater privacy protection and reform at the state
and federal level in response to precedents set forth by the General Data Protection Regulation (the "GDPR") and the California
Consumer Privacy Act (the "CCPA"). The development and evolving nature of domestic and international privacy regulation
and enforcement could impact and potentially limit how NRG processes personally identifiable information. The 2020
enactment of the CCPA granted certain data access rights to California residents with respect to their personal information, and
with the forthcoming amendments to the CCPA supported by the California Privacy Rights Act (the “CPRA”), effective
January 1, 2023, California residents will have increased access rights (including the right to limit the use and disclosure of
sensitive personal information), which will be enforced by a new state privacy regulator, resulting in more scrutiny of business
practices and disclosures. Additional states including Virginia, Colorado, and Nevada have similarly adopted enhanced data
privacy legislation patterned after the standards set forth by CCPA, including broader data access rights, with Virginia going a
step further requiring businesses to perform data protection assessments for certain processing activities.
As new laws and regulations are created, requiring businesses to implement processes to enable customer access to their
data and enhanced data protection and management standards, NRG cannot forecast the impact that they may have on the
Company’s business. Any non-compliance with laws may result in proceedings or actions against the Company by
governmental entities or individuals. Moreover, any inquiries or investigations, government penalties or sanctions, or civil
actions by individuals may be costly to comply with, resulting in negative publicity, increased operating costs, significant
management time and attention, and may lead to remedies that harm the business, including fines, demands or orders that
existing business practices be modified or terminated.
NRG's retail operations are subject to changing rules and regulations that could have a material impact on the Company's
profitability.
The competitiveness of NRG's retail operations partially depends on regulatory policies that establish the structure, rules,
terms and conditions on which services are offered to retail customers. These policies can include, among other things, controls
on the retail rates that NRG 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. The Company's retail operations 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, federal or provincial
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.
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. 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 a 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.
Risks Related to Public Health Threats
Public health threats or outbreaks of communicable diseases could have a material adverse effect on the Company’s
operations and financial results.
The Company may face risks related to public health threats or outbreaks of communicable diseases. A widespread
healthcare crisis, such as an outbreak of a communicable disease, could adversely affect the global economy and the
Company’s ability to conduct its business for an indefinite period of time. For example, the ongoing global COVID-19
pandemic negatively impacted local and global economies, disrupted financial markets and international trade, resulted in
increased unemployment levels and impacted local and global supply chains, all of which negatively impact the electricity
industry and the Company’s business. Federal, state, and local governments had implemented various mitigation measures,
including travel restrictions, border closings, restrictions on public gatherings, shelter-in-place orders and limitations on
business activities. Although the operations of the Company are considered an essential service, some of these measures may
adversely impact the ability of NRG employees, contractors, suppliers, customers, and other business partners to conduct
35
business activities. This could have a material adverse effect on the Company’s results of operations, financial condition, risk
exposure and liquidity.
In particular, the continued spread of COVID-19 and efforts to contain the virus could:
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adversely impact demand for the Company’s electricity services and other products and services and the ability of
customers to pay their bills;
cause an increase in costs for the Company as a result of emergency measures taken by state and local regulatory
authorities in response to the COVID-19 crisis, including regulatory changes prohibiting customer disconnects and late
fees;
impact the ability of the Company's partners or counterparties to perform their obligations under existing
arrangements, including development projects, power purchase and sale arrangements, hedging arrangements or other
commercial activities; and
cause other unpredicted events which may have an adverse impact on the Company’s results of operations, financial
condition, risk exposure and liquidity.
The situation surrounding COVID-19 remains fluid and the potential for a material impact on the Company’s results of
operations, financial condition, risk exposure and liquidity increases the longer the virus, or any variants thereof, impacts the
level of economic activity in the United States and abroad. NRG cannot reasonably estimate with any degree of certainty the
future impact of COVID-19, or any resurgence of COVID-19 or other pandemic may have on the Company’s results of
operations, financial position, risk exposure and liquidity.
Risks Related to the Economic and Financial Market Conditions, and the Company's Indebtedness
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 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;
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;
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; and
exposing NRG to the risk of increased interest rates because certain of its borrowings are at variable rates of interest,
primarily through its Revolving Credit Facility.
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The Company’s credit documents contain financial and other restrictive covenants that may limit the Company's ability to
return capital to stockholders or otherwise engage in activities that may be in its long-term best interests. NRG's failure to
comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of
all of the Company's indebtedness. The Company's corporate credit agreement includes a sustainability-linked metric and
sustainability-linked bonds, which could result in increased interest expense to the Company if the sustainability metrics set
forth therein are not met. 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.
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.
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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 results of operations. The breadth and depth of negative economic conditions may have a wide-
ranging impact on the U.S. business environment. 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. 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 energy and other factors may negatively impact the trading price of NRG’s
common stock and impact forecasted cash flows, which may require NRG to evaluate its goodwill and other long-lived assets
for impairment. Any such impairment could have a material impact on NRG’s financial statements.
Goodwill and other intangible assets that NRG has recorded in connection with its acquisitions are subject to 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.
Goodwill is not amortized but is reviewed annually or more frequently for impairment. Other intangibles are also
reviewed at least annually or more frequently, if certain conditions exist, and are 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.
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Annual Report on Form 10-K of NRG Energy, Inc., or NRG or the Company, includes forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933, as amended, or Securities Act, and Section 21E of the
Securities Exchange Act of 1934, as amended, or Exchange Act. The words "believes," "projects," "anticipates," "plans,"
"expects," "intends," "estimates" and similar expressions are intended to identify forward-looking statements. These forward-
looking statements involve known and unknown risks, uncertainties and other factors that may cause NRG's actual results,
performance and achievements, or industry results, to be materially different from any future results, performance or
achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the
factors described under Item 1A — Risk Factors and the following:
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Business uncertainties related to the integration of the operations of Direct Energy with its own;
NRG's ability to obtain and maintain retail market share;
General economic conditions, changes in the wholesale power and gas markets and fluctuations in the cost of fuel;
Volatile power and gas supply costs and demand for power and gas;
Changes in law, including judicial and regulatory 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;
NRG's ability to enter into contracts to sell power or gas and procure fuel on acceptable terms and prices;
NRG's inability to estimate with any degree of certainty the future impact that COVID-19, any resurgence of
COVID-19, or other pandemic may have on NRG's results of operations, financial position, risk exposure and
liquidity;
NRG's ability to successfully integrate, realize cost savings and manage any acquired businesses;
NRG's ability to engage in successful acquisitions and divestitures, as well as other mergers and acquisitions activity;
Cyber terrorism and inadequate cybersecurity, data breaches 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;
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;
The liquidity and competitiveness of wholesale markets for energy commodities;
Government regulation, including changes in market rules, rates, tariffs and environmental laws;
NRG's ability to develop and innovate new products, as retail and wholesale markets continue to change and evolve;
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;
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 in the future;
Operating and financial restrictions placed on NRG and its subsidiaries that are contained in NRG's corporate credit
agreements, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;
The ability of NRG and its counterparties to develop and build new power generation facilities;
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 market initiatives, corporate efficiencies, asset
strategy, and a range of other programs throughout NRG to reduce costs or generate revenues;
NRG's ability to successfully evaluate investments and achieve intended financial results in new business and growth
initiatives;
38
•
NRG's ability to develop and maintain successful partnering relationships as needed.
Forward-looking statements speak only as of the date they were made, and NRG 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.
39
Item 2 — Properties
Listed below are descriptions of NRG's interests in facilities, operations and/or projects owned or leased as of
December 31, 2021. The rated MW capacity figures provided represent nominal summer MW capacity of power generated. Net
MW capacity is adjusted for the Company's owned or leased interest as of December 31, 2021. The Company believes its
existing facilities, operations and/or projects are suitable for the conduct of its business. The following table summarizes NRG's
power production and cogeneration facilities by region:
Name of Facility
Power Market
Plant Type
Primary Fuel
Location Rated MW Capacity(a) Net MW Capacity(b) % Owned
Total Texas
11,809
10,083
Texas
Cedar Bayou
Cedar Bayou 4
Elbow Creek
Greens Bayou
Gregory
Limestone(c)
Petra Nova Cogen
San Jacinto
South Texas Project
T.H. Wharton
W.A. Parish
W.A. Parish
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
East
Astoria Turbines(e)
NYISO
Chalk Point
Fisk
Indian River(f)
Indian River
Joliet
Powerton
Vienna
Waukegan(f)
Waukegan
Will County(f)
West/Other
Cottonwood
Gladstone
Ivanpah
Midway-Sunset
Stadiums and Other
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
PJM
MISO
CAISO
CAISO
Fossil
Fossil
Other
Fossil
Fossil
Fossil
Fossil
Fossil
Natural Gas
Natural Gas
TX
TX
Battery Storage TX
Natural Gas
Natural Gas
Coal
Natural Gas
Natural Gas
TX
TX
TX
TX
TX
TX
TX
TX
TX
Nuclear
Uranium
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Fossil
Natural Gas
Coal
Natural Gas
Natural Gas
Natural Gas
Oil
Coal
Oil
Natural Gas
Coal
Oil
Coal
Oil
Coal
NY
MD
IL
DE
DE
IL
IL
MD
IL
IL
IL
Total East
Fossil
Fossil
Renewable
Natural Gas
Coal
Solar
Fossil
Natural Gas
TX
AUS
CA
CA
Renewable
Solar
various
1,494
504
2
330
385
1,660
68
160
2,572
1,002
2,514
1,118
1,494
252
2
330
385
1,660
34
160
1,132
1,002
2,514
1,118
420
80
171
410
16
1,381
1,538
167
682
101
510
5,476
1,177
1,613
393
226
5
416
3,830
21,115
420
80
171
410
16
1,381
1,538
167
682
101
510
5,476
1,177
605
214
113
5
204
2,318
17,877
100.0
50.0
100.0
100.0
100.0
100.0
50.0
100.0
44.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
___(d)
37.5
54.5
50.0
100.0
49.0
Watson
CAISO
Fossil
Natural Gas
CA
Total West/Other
Total Fleet
(a) MW capacity of the facility without taking into account NRG ownership percentage
(b) Actual capacity can vary depending on factors including weather conditions, operational conditions, and other factors. Additionally, ERCOT and PJM
(c)
require periodic demonstration of capability, and the capacity may vary individually and in the aggregate from time to time
In early July 2021, Limestone Unit 1 came offline as a result of damage to the duct work associated with the flue gas desulfurization system. Based on
management's current assessment of necessary remediation efforts, Unit 1 is expected to remain on an outage until the second quarter of 2022
(d) NRG leases 100% interests in the Cottonwood facility through a facility lease agreement expiring in May 2025 and operates the Cottonwood facility
(e) On February, 22, 2022, NRG submitted deactivation notices to the NYISO for the Astoria facility, with a planned retirement date of 2023
40
(f) During the second quarter of 2021, the results of the PJM Base Residual Auction for the 2022/2023 delivery year were released, leading the Company to
announce the near-term retirement of a significant portion of its PJM coal generating assets as detailed bellow:
Name of Facility
Indian River 4
Waukegan 7
Waukegan 8
Will County
Power Market
Primary Fuel
Net MW Capacity
Retirement Date
PJM
PJM
PJM
PJM
Coal
Coal
Coal
Coal
Total
410
328
354
510
1,602
June 2022*
June 2022
June 2022
June 2022
* On July 30, 2021, PJM identified reliability impacts resulting from the proposed deactivation of one of those assets, Indian River Unit 4. On August 27, 2021
the Company notified PJM that it would continue operations at Indian River Unit 4 until the reliability upgrades identified by PJM were completed, provided
that the unit receives a satisfactory and compensatory reliability must run arrangement.
Other Properties
NRG owns several real properties and facilities related to its generation assets, other vacant real property unrelated to its
generation assets, 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 operational and corporate headquarters at 910 Louisiana Street, Houston, Texas, its financial and
commercial corporate offices at 804 Carnegie Center, Princeton, New Jersey, as well as its retail operations offices, call centers,
and various other office space.
Item 3 — Legal Proceedings
See Item 15 — Note 23, 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
There have been no events that are required to be reported under this Item.
41
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 common stock trades on the New York Stock Exchange under the symbol "NRG." 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. 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 21, Stock-Based Compensation, to the Consolidated Financial Statements.
As of January 31, 2022, there were 16,501 common stockholders of record.
NRG increased the annual dividend to $1.30 from $1.20 per share beginning in the first quarter of 2021 and further
increased the annual dividend by 8% to $1.40 per share beginning in the first quarter of 2022 . NRG expects to target an annual
dividend growth rate of 7-9% per share in subsequent years.
Issuer Purchases of Equity Securities
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, 2021.
Total Number of
Shares
Purchased
Average Price
Paid per Share(b)
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(a)(c)
For the three months ended
December 31, 2021
Month #1 . . . . . . . . . . . . . . . . .
(October 1, 2021 to October
31, 2021 . . . . . . . . . . . . . . . . . .
Month #2 . . . . . . . . . . . . . . . . .
(November 1, 2021 to
November 30, 2021, . . . . . . . . .
Month #3 . . . . . . . . . . . . . . . . .
(December 1, 2021 to
December 31, 2021) . . . . . . . . .
— $
— $
1,084,752 $
—
—
40.85
40.85
— $
— $
—
—
1,084,752 $
1,084,752
955,665,275
Total at December 31, 2021 . . .
1,084,752 $
(a) On December 6, 2021 the Company announced that the Board of Directors has authorized $1 billion for share repurchases, as part of NRG’s Capital
Allocation Program. The program began in December 2021 and will continue throughout 2022
(b) The average price paid per share excludes commissions of $0.02 per share paid in connection with the open market share repurchases
(c) Includes commissions of $0.02 per share paid in connection with the open market share repurchases
42
Stock Performance Graph
The performance graph below compares the cumulative total stockholder return on NRG's common stock for the period
December 31, 2016 through December 31, 2021 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.
The performance graph shown below is being furnished and compares each period assuming that $100 was invested on
December 31, 2016, 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
12/31/2016
12/31/2017
12/31/2018
12/31/2019
12/31/2020
12/31/2021
NRG Energy, Inc. . . . . . . . . . . . . . . . . . . . . . . $ 100.00 $ 233.70 $ 326.22 $ 328.47 $ 321.43 $ 381.07
233.41
S&P 500 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
179.90
UTY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
153.17
148.11
121.83
112.82
116.49
116.79
181.35
152.14
100.00
100.00
Item 6 — Reserved
43
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 the Company operates, a discussion of regulation,
weather, competition and other factors that affect the business, and other significant events that are important to
understanding the results of operations and financial condition;
Results of operations for the years ended December 31, 2021 and December 31, 2020, 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, contractual obligations and market commitments, and off-balance sheet arrangements; and
Critical accounting estimates that are most important to both the portrayal of the Company's financial condition and
results of operations, and require management's most difficult, subjective, or complex judgments.
As you read this discussion and analysis, refer to NRG's Consolidated Statements of Operations in this Form 10-K, which
present the results of the Company's operations for the years ended December 31, 2021 and 2020, and also refer to Item 1 to
this Form 10-K for more detail discussion about the Company's business. A discussion and analysis of fiscal year 2019 may be
found in Part II, Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations of the
Annual Report on Form 10-K for the fiscal year ended December 31, 2020.
As further described in Item 15 — Note 4, Acquisitions, Discontinued Operations and Dispositions, to the Consolidated
Financial Statements, the Company determined in prior years that the following businesses were discontinued operations and
recast to present their results in the corporate segment:
•
•
•
South Central Portfolio
NRG Yield, Inc. and its Renewables Platform
Carlsbad
Executive Summary
NRG Energy, Inc., or NRG or the Company, is a consumer services company built on dynamic retail brands. NRG brings
the power of energy to customers by producing and selling energy and related products and services, nation-wide in the U.S.
and Canada in a manner that delivers value to all of NRG's stakeholders. NRG sells power, natural gas, home and power
services, and develops innovative, sustainable solutions, predominately under the brand names NRG, Reliant, Direct Energy,
Green Mountain Energy, Stream, and XOOM Energy. The Company has a customer base that includes approximately 6 million
Home customers as well as commercial, industrial, and wholesale customers, supported by approximately 18,000 MW of
generation as of December 31, 2021.
Business Environment
The industry dynamics and external influences affecting the Company, its businesses, and the retail energy and power
generation industry in 2021 and for the future medium term include:
Market Dynamics — 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 customers and producers. In 2021, the average natural gas price at Henry
Hub was 85% higher than in 2020.
NRG may experience impacts to gross margins due to significant, rapid changes in current natural gas prices and the lag
in our ability to make a corresponding adjustment to the retail rates we charge customers on term and month to month contracts.
The Company hedges its load commitments in order to mitigate the impact of changes in commodity prices, and as a result,
these gross margin impacts would be realized in future periods until we are able to make the corresponding adjustments to the
retail customer rates.
Natural gas prices are a primary driver of coal demand. Coal commodity prices increased significantly in 2021, which is
partly due to supply chain disruptions, as further discussed below in Global Supply Chain Disruptions, as well as stressed coal
equities, which has led coal suppliers to file for bankruptcy protection, launch debt exchanges, rationalize assets, and cut
production.
44
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, 2021 and 2020. The average on-peak power prices increased significantly in Texas due to the impact from
Winter Storm Uri. The average on-peak power prices increased in East and West/Services/Other due to higher natural gas
prices.
Region
Texas (a)
ERCOT - Houston(a)
ERCOT - North(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
East
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NY J/NYC(b)
NEPOOL(b)
COMED (PJM)(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PJM West Hub(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
West
CAISO - SP15(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MISO - Louisiana Hub(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average On-Peak Power Price ($/MWh)
Year Ended December 31,
2020
2021
2021 vs 2020
Change %
192.17 $
189.05
48.71
51.81
41.33
45.67
53.53
43.05
27.65
25.85
24.55
26.52
22.48
24.49
38.15
24.43
595 %
631 %
98 %
95 %
84 %
86 %
40 %
76 %
(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
The following table summarizes average realized power prices for NRG, including the impact of settled hedges, for the
years ended December 31, 2021 and 2020:
Segment
East(a)
West/Services/Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Average Realized Power Price ($/MWh)
Year Ended December 31,
2020
2021
2021 vs 2020
Change %
36.33 $
43.63
34.92
34.80
4 %
25 %
(a) Average Realized Power Price reflects energy sales from the generation fleet, including sales to the retail component of the East Segment. Intercompany
financial transactions hedging generation with the retail operations make up ($8.03)/MWh in the year ended December 31, 2021 and $12.18/MWh in the year
ended December 31, 2020
The average realized power prices increased less than average on peak power prices for the year ended December 31,
2021, as compared to the same period in 2020, due to the Company's multi-year hedging program impacting average realized
power prices, while on peak power prices increased due to increased natural gas prices and warmer June temperatures in
California.
Increased Awareness of, and Action to Combat, Climate Change — Diverse groups of stakeholders, including investors,
asset managers, financial institutions, non-government organizations, industry coalitions, individual companies, consumer
groups and academic institutions, are increasingly engaged in efforts to limit global warming in the post-industrial era to well
below 2 degrees Celsius. As a result, policymakers and regulators at regional, national, sub-national and local levels of
government, both in the United States and other parts of the world, are increasingly focused on actions to combat climate
change.
NRG actively monitors climate change related developments that could impact its business and regularly engages with a
diverse set of stakeholders on these issues. Such engagement helps the Company identify and pursue potential opportunities
both to decarbonize its business and better serve its customers. NRG is committed to providing transparent disclosures of its
climate risks and opportunities to stakeholders. The Company became an early supporter of the Task Force on Climate-related
Financial Disclosures ("TCFD") recommendations after they were issued in 2017, published a TCFD mapping disclosure in
December 2020 and issued a stand-alone TCFD report in December 2021.
45
Lower Carbon 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 lower
carbon infrastructure technologies. In addition, the costs associated with the development of lower carbon infrastructure, such
as wind and solar generating facilities, continue to decline. These factors continue to drive increases in the development of
lower carbon 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, 39% of 2021 energy consumption in the ERCOT
market was generated from carbon emission-free resources, with wind power contributing 24%. In addition, subsidies and
incentives have contributed to the increase in renewable power sources, and customer awareness and preferences are shifting
toward sustainable solutions. Increased demand for sustainable energy products from both residential and commercial
customers creates opportunities for diversified product offerings in competitive retail markets.
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, customers 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 conducts 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's operations are typically not exposed to the effects of
extreme weather in all parts of its business at once. A significant portion of the Company's business is located within Texas, and
extreme weather conditions occurring in Texas may have a material impact on the Company's financial position.
For discussion of the recent weather event in Texas, see Significant Events - Extreme Weather Event in Texas During
February 2021 and expected Uplift Securitization Proceeds below.
Global Supply Chain Disruptions — There are currently global supply chain disruptions impacting natural gas, coal and
other fuels and materials necessary for the production and sale of electricity to our retail customers. These supply chain
disruptions are due in part to increased demand driven by a number of factors outside the Company's control including the
COVID-19 pandemic, labor shortages and extreme weather events in the U.S. These factors are impacting the dispatch of
generation facilities, as well as the costs to serve our retail customers. The Company expects supply chain disruptions will
continue throughout the remainder of 2022. We are working closely with our suppliers and customers to minimize any potential
adverse impacts of these events. We will continue to actively monitor all direct and indirect potential impacts of the supply
chain disruptions, and will seek to mitigate and minimize their impact on our business.
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.
46
Environmental Matters, Regulatory Matters and Legal Proceedings — Details of environmental matters are presented in
Item 15 — Note 25, Environmental Matters, to the Consolidated Financial Statements and Item 1 — Business, Environmental
Matters. Details of regulatory matters are presented in Item 15 — Note 24, Regulatory Matters, to the Consolidated Financial
Statements and Item 1 — Business, Regulatory Matters. Details of legal proceedings are presented in Item 15 — Note 23,
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.
Significant Events
The following significant events occurred during 2021 and through the filing date, as further described within this
Management's Discussion and Analysis and the consolidated financial statements:
Financing Activities
On August 23, 2021, the Company issued $1.1 billion of aggregate principal amount at par of 3.875% senior notes due
2032 (the "2032 Senior Notes"). The 2032 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain
of its subsidiaries. The 2032 Senior Notes were issued under NRG's Sustainability-Linked Bond Framework, which sets out
certain sustainability targets, including reducing greenhouse gas emissions. Failure to meet such sustainability targets will result
in a 25 basis point increase to the interest rate payable on the 2032 Senior Notes from and including August 15, 2026.
During the year ended December 31, 2021, the Company redeemed $1.9 billion in aggregate principal of its Senior Notes
for $1.9 billion using the proceeds of the 2032 Senior Notes and cash on hand.
Extreme Weather Event in Texas During February 2021 and expected Uplift Securitization proceeds
During February 2021, Texas experienced unprecedented cold temperatures for a prolonged duration as a result of Winter
Storm Uri, resulting in a power emergency, blackouts, and an estimated all-time peak demand of 77 GW (without load shed).
Ahead of the event, NRG launched residential customer communications calling for conservation across all of its brands, and
initiated residential and commercial and industrial demand response programs to curtail customer load. The Company
maximized available generating capacity and brought in additional resources to supplement in-state staff with technical and
operating experts from the rest of its U.S. fleet.
The Texas Legislature passed House Bill 4492, which among other things, authorized ERCOT to obtain $2.1 billion of
financing to distribute to LSEs that were charged and paid to ERCOT exceptionally highly priced ORDPA and ancillary service
costs during Winter Storm Uri. Based on LSE-level detail published by the PUCT on December 7, 2021, NRG will receive
$689 million from ERCOT.
During the year ended December 31, 2021, Winter Storm Uri's pre-tax financial impact to the Company was a loss of
$380 million, which reflects the recovery of $689 million of cost of operations as a result of the proceeds we will receive from
the Uplift Securitization discussed above, with receipt expected to occur during the second quarter of 2022. The Company
continues to pursue additional mitigants including, but not limited to, customer bad debt mitigation, counterparty default
recovery, and additional ERCOT default recovery.
Direct Energy Acquisition
On January 5, 2021, the Company acquired Direct Energy, which had been a North American subsidiary of Centrica.
Direct Energy is a leading retail provider of electricity, natural gas, and home and business energy related products and services
in North America, with operations in all 50 U.S. states and 8 Canadian provinces. The acquisition increased NRG's retail
portfolio by over 3 million customers and complements its integrated model. It also broadened the Company's presence in the
Northeast and into states and locales where it did not previously operate, supporting NRG's objective to diversify its business.
See Item 15 — Note 4, Acquisitions, Discontinued Operations and Dispositions, to the Consolidated Financial Statements for
further discussion.
Limestone Extended Outage
In early July 2021, Limestone Unit 1 came offline as a result of damage to the duct work associated with the flue gas
desulfurization system. Based on management's current assessment of necessary remediation efforts, Limestone Unit 1 is
expected to remain on an outage until the second quarter of 2022.
PJM Base Residual Auction results and Planned Retirement of 1,600 MWs of PJM Coal Capacity
During the second quarter of 2021, the results of the PJM Base Residual Auction for the 2022/2023 delivery year were
released, leading the Company to announce the near-term retirement of a significant portion of its PJM coal generating assets in
June 2022. On July 30, 2021, PJM identified reliability impacts resulting from the proposed deactivation of one of those assets,
Indian River Unit 4. On August 27, 2021 the Company notified PJM that it would continue operations at Indian River Unit 4
until the reliability upgrades identified by PJM were completed, provided that the unit receives a satisfactory and compensatory
'reliability must run' arrangement.
47
The Company recorded impairment losses of $271 million and $35 million on the PJM generating assets and Midwest
Generation goodwill, respectively, in connection with the decline in PJM capacity prices and the near-term retirement dates of
certain assets. See Item 15 — Note 11, Asset Impairments to the Consolidated Financial Statements for further discussion. The
Company is continuing to evaluate the viability of the remaining PJM generating assets.
Sale of 4.8 GW of Fossil Generation Assets
On December 1, 2021, the Company sold approximately 4,850 MWs of fossil generating assets from its East and West
regions of operations to Generation Bridge, an affiliate of ArcLight Capital Partners. As part of the transaction, NRG entered
into a tolling agreement for the 866 MW Arthur Kill plant in New York City through April 2025. See Item 15 — Note 4,
Acquisitions, Discontinued Operations and Dispositions, to the Consolidated Financial Statements for further discussion.
Sale of Agua Caliente
On February 3, 2021, the Company completed the sale of its 35% ownership in Agua Caliente to Clearway Energy, Inc.
for $202 million. NRG recognized a gain on the sale of $17 million, including cash disposed of $7 million.
Share Repurchases
In December 2021, the Company's board of directors authorized the Company to repurchase $1.0 billion of its common
stock. Through December 31, 2021, the Company completed $53 million of share repurchases at an average price of $40.22 per
share, including $9 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances.
Through February 24, 2022, an additional $82 million of share repurchases were executed at an average price of $40.26 per
share, including $6 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances. See
Item 15 - Note 16, Capital Structure, to the Consolidated Financial Statements for additional discussion.
Renewable Power Purchase Agreements
The Company's strategy is to procure mid to long-term generation through power purchase agreements. As of December
31, 2021, NRG has entered into PPAs totaling approximately 2.6 GW with third-party project developers and other
counterparties. The average tenor of these agreements is twelve years. The Company expects to continue evaluating and
executing similar agreements that support the needs of the business. The total GW entered into through PPAs may be impacted
by contract terminations when they occur.
Dividend Increase
In the first quarter of 2021, NRG increased the annual dividend to $1.30 from $1.20 per share. In 2022, NRG further
increased the annual dividend to $1.40 per share, representing an 8% increase from 2021. The Company expects to target an
annual dividend growth rate of 7-9% per share in subsequent years.
COVID-19
While the pandemic presented risks, as further described in Part II, Item 1A — Risk Factors of this Form 10-K, to the
Company’s business, there was not a material adverse impact on the Company’s results of operations for the years ended
December 31, 2021 and 2020.
48
Consolidated Results of Operations for the years ended December 31, 2021 and 2020
The following table provides selected financial information for the Company:
(In millions, except otherwise noted)
Operating Revenues
Retail revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Energy revenue(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capacity revenue(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mark-to-market for economic hedging activities . . . . . . . . . . . . . . . . . . .
Contract amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenues(a)(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating Costs and Expenses
Cost of fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased energy and other cost of sales(c)
. . . . . . . . . . . . . . . . . . . . . . . .
Mark-to-market for economic hedging activities . . . . . . . . . . . . . . . . . . .
Contract and emissions credit amortization(c)
. . . . . . . . . . . . . . . . . . . . . .
Operations and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other cost of operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of operations (excluding depreciation and amortization shown
below) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selling, general and administrative costs . . . . . . . . . . . . . . . . . . . . . . . . .
Provision for credit losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition-related transaction and integration costs . . . . . . . . . . . . . . . .
Total operating costs and expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates . . . . . . . . . . . . . . . . . . . . .
Impairment losses on investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on debt extinguishment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total other expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income Before Income Taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu) . . . . . . . . . . . . . . . . . $
(a)
(b)
(c)
Includes realized gains and losses from financially settled transactions
Includes trading gains and losses and ancillary revenues
Includes amortization of SO2 and NOx credits and excludes amortization of RGGI credits
Gross Margin
Year Ended December 31,
2020
2021
Change
23,561 $
1,215
775
(164)
(30)
1,632
26,989
1,844
19,766
(2,880)
43
1,370
339
20,482
785
544
1,293
698
93
23,895
247
3,341
17
—
63
(77)
(485)
(482)
2,859
672
7,460 $ 16,101
676
95
(259)
(30)
1,313
17,896
539
680
95
—
319
9,093
851
4,069
214
5
1,129
272
6,540
435
75
810
108
23
7,991
3
1,105
17
(18)
67
(9)
(401)
(344)
761
251
(993)
(15,697)
3,094
(38)
(241)
(67)
(13,942)
(350)
(469)
(483)
(590)
(70)
(15,904)
244
2,236
—
18
(4)
(68)
(84)
(138)
2,098
421
1,677
2,187 $
510 $
3.84 $
2.08
85 %
The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of fuel,
purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emission credit
amortization and depreciation and amortization.
49
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 retail revenue, energy revenue, capacity revenue and other revenue, less cost of fuels, purchased
energy 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, depreciation and amortization, operations and maintenance, or
other costs of operations.
The tables below present the composition and reconciliation of gross margin and economic gross margin for the years
ended December 31, 2021 and 2020:
($ in millions, except otherwise noted)
Texas
East
West/
Services/
Other
Corporate/
Eliminations
Total
Retail revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
8,410 $
11,862 $
3,290 $
(1) $
23,561
Year Ended December 31, 2021
1,215
775
(164)
(30)
1,632
26,989
(1,844)
(19,766)
2,880
(43)
(785)
7,431
2,716
(73)
(785)
Energy revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capacity revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mark-to-market for economic hedging activities . . . . . . . . . . . . . . . . . .
Contract amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating revenue(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased energy and other costs of sales(b)(c)(d)
. . . . . . . . . . . . . . . . . .
Mark-to-market for economic hedging activities . . . . . . . . . . . . . . . . .
Contract and emission credit amortization . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
329
—
(3)
—
1,557
10,293
(1,424)
(6,108)
988
2
(331)
508
718
(88)
(26)
59
13,033
(196)
(10,775)
1,803
(28)
(338)
371
57
(86)
(4)
25
3,653
(224)
(2,882)
102
(17)
(88)
7
—
13
—
(9)
10
—
(1)
(13)
—
(28)
Gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
3,420 $
3,499 $
544 $
(32) $
Less: Mark-to-market for economic hedging activities, net . . . . . . . . . .
Less: Contract and emission credit amortization, net . . . . . . . . . . . . . . .
Less: Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . .
Economic gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(a) Includes trading gains and losses and ancillary revenues
985
2
(331)
1,715
(54)
(338)
16
(21)
(88)
—
—
(28)
2,764 $
2,176 $
637 $
(4) $
5,573
(b) Includes capacity and emissions credits
(c) Includes $2,648 million, $183 million and $1,033 million of TDSP expense in Texas, East, and West/Services/Other respectively
(d) Excludes depreciation and amortization shown separately
Business Metrics
Texas
East
West/
Services/
Other
Corporate/
Eliminations
Home electricity sales volume (GWh) . . . . . . . . . . . . . . . . . . . . . . . . . .
Business electricity sales volume (GWh) . . . . . . . . . . . . . . . . . . . . . . .
Home natural gas retail sales volumes (MDth) . . . . . . . . . . . . . . . . . . .
Business natural gas retail sales volumes (MDth) . . . . . . . . . . . . . . . . .
Average retail Home customer count (in thousands)(a) . . . . . . . . . . . . .
Ending retail Home customer count (in thousands)(a) . . . . . . . . . . . . . .
GWh sold . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
GWh generated(b) (c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
42,397
34,367
—
—
3,055
3,024
36,920
36,920
14,108
53,204
74,920
2,252
10,625
97,272
1,595,533
109,021
1,844
1,766
11,452
7,494
962
932
8,503
7,949
—
—
—
—
—
—
—
—
(a) Home customer count includes recurring residential customers, services customers and municipal aggregations
(b) Includes owned and leased generation, excludes tolled generation and equity investments
(c) Includes 1,054 GWh and 2,445 GWh in East and West/Services/Other respectively that was sold to Generation Bridge in December 2021
Total
58,757
98,196
172,192
1,704,554
5,861
5,722
56,875
52,363
50
Year Ended December 31, 2020
($ in millions, except otherwise noted)
Texas
East
West/
Services/
Other(a)
Corporate/
Eliminations
Total
Retail revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Energy revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capacity revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mark-to-market for economic hedging activities . . . . . . . . . . . . . . . . .
Other revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchased energy and other costs of sales(a)(b)(c) . . . . . . . . . . . . . . . . .
Mark-to-market for economic hedging activities . . . . . . . . . . . . . . . .
Contract and emission credit amortization . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Less: Mark-to-market for economic hedging activities, net . . . . . . . . .
Less: Contract and emission credit amortization . . . . . . . . . . . . . . . . . .
Less: Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . .
6,061 $
1,305 $
96 $
(2) $
7,460
24
—
2
222
6,309
(546)
(3,110)
(211)
(5)
(227)
183
620
88
62
2,258
(151)
(876)
5
—
(138)
333
61
(3)
43
530
(154)
(89)
—
—
(36)
(1)
(1)
8
(8)
(4)
—
6
(8)
—
(34)
539
680
95
319
9,093
(851)
(4,069)
(214)
(5)
(435)
2,210 $
1,098 $
251 $
(40) $
3,519
(209)
(5)
(227)
93
—
(138)
(3)
—
(36)
—
—
(34)
(119)
(5)
(435)
Economic gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2,651 $
1,143 $
290 $
(6) $
4,078
(a) Includes capacity and emissions credits
(b) Includes $1,967 million and $10 million of electric TDSP charges for Texas and East, respectively
(c) Excludes depreciation and amortization shown separately
Business Metrics
Texas
East
West/
Services/
Other
Corporate/
Eliminations
Total
Home electricity sales volume (GWh) . . . . . . . . . . . . . . . . . . . . . . . . . .
Business electricity sales volume (GWh) . . . . . . . . . . . . . . . . . . . . . . .
Natural gas retail sales volumes (MDth) . . . . . . . . . . . . . . . . . . . . . . . .
Average retail Home customer count (in thousands)(a)
Ending retail Home customer count (in thousands)(a)
. . . . . . . . . . . . . .
. . . . . . . . . . . . .
GWh sold . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
GWh generated(b)(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
38,473
17,928
—
2,449
2,451
31,385
31,385
10,221
1,596
23,509
1,175
1,136
8,136
4,102
—
—
—
—
—
9,569
9,171
—
—
—
—
—
—
—
48,694
19,524
23,509
3,624
3,587
49,090
44,658
(a) Home customer count includes recurring residential customers and municipal aggregations
(b) Includes owned and leased generation, excludes tolled generation and equity investments
(c) Includes 1,192 GWh and 3,002 GWh in East and West/Services/Other respectively that was sold to Generation Bridge in December 2021
51
The table below represents the weather metrics for 2021 and 2020:
Year ended
December 31,
Quarter ended
December 31,
Quarter ended
September 30,
Quarter ended
June 30,
Quarter ended
March 31,
Texas
East West/
Services
/Other(a)
Texas
East West/
Services
/Other(a) Texas
East West/
Services
/Other(a)
Texas
East West/
Services
/Other(a)
Texas
East West/
Services
/Other(a)
2,960
1,275
1,877
386
91
185
1,589
784
1,134
899
362
521
86
38
37
1,562
4,306
2,060
360
1,377
662
—
38
5
82
541
192
1,120
2,350
1,201
3,102
1,362
1,971
280
79
181
1,640
874
1,152
1,012
353
562
170
56
1,501
4,268
1,939
634
1,517
763
6
72
4
70
634
178
791
2,045
76
994
3,090
1,297
1,924
281
85
157
1,690
818
1,159
1,003
356
557
116
38
51
1,691
4,558
2,044
693
1,584
774
2
56
10
59
521
193
937
2,397
1,067
Weather
Metrics
2021
CDDs(b)
HDDs(b)
2020
CDDs
HDDs
10-year
average
CDDs
HDDs
(a) The West/Services/Other weather metrics are comprised of the average of the CDD and HDD regional results for the West - California and West - South Central
regions
(b) 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
Winter Storm Uri
During the year ended December 31, 2021, Winter Storm Uri's pre-tax financial impact to the Company was a loss of
$380 million, which reflects the recovery of $689 million of cost of operations as a result of the expected proceeds from the
Uplift Securitization. The following impacts are further discussed in the related sections below:
Gross margin - Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Gross margin - East . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross margin - West/Services/Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operations and maintenance expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selling, general and administrative costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provision for credit losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total impact to loss before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(In millions)
88
146
13
247
(2)
(29)
(596)
(380)
The Company continues to pursue additional mitigants including, but not limited to, customer bad debt mitigation,
counterparty default recovery, and additional ERCOT default recovery.
52
Gross margin and economic gross margin
Gross margin increased $3.9 billion and economic gross margin increased $1.5 billion, both of which include
intercompany sales, during the year ended December 31, 2021, compared to the same period in 2020. The detail by segment is
as follows:
Texas
(In millions)
Higher gross margin due to Winter Storm Uri, primarily driven by hedging optimization, partially offset by the
negative impact of an increase in unhedgeable ancillary and operating reserve demand curve, net of
securitization proceeds of $689 million . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
The following explanations exclude the impact of Winter Storm Uri:
Higher gross margin due to increased volumes from the acquisition of Direct Energy in January 2021 . . . . . . . .
Higher gross margin due to market optimization activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lower gross margin due to a 22% increase in overall average costs to serve the retail load, driven primarily by
increases in power, ancillary, fuel costs and the effect of the current year Limestone Unit 1 extended forced
outage, totaling $349 million, partially offset by higher net revenue primarily driven by increased net revenue
rates as a result of changes in customer term, product and mix of $2.50 per MWh, or $156 million . . . . . . . . .
Lower net revenue due to a decrease in load of 834,000 MWhs from weather . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lower net revenue due to attrition and customer mix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Decrease in contract and emission credit amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
88
280
9
(193)
(72)
(5)
6
113
1,194
7
(104)
1,210
East
(In millions)
Higher gross margin due to Winter Storm Uri, primarily driven by natural gas optimization during volatile
pricing that occurred during the weather event . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
146
The following explanations exclude the impact of Winter Storm Uri:
Higher gross margin due to increased volumes from the acquisition of Direct Energy in January 2021, including
$503 million from natural gas activity and $436 million from power activity . . . . . . . . . . . . . . . . . . . . . . . . . . .
Higher business demand response gross margin primarily from the early settlement of capacity obligations in
2021 compared to the same period in 2020 of $63 million and higher volumes sold in 2021 of $10 million . . .
Higher gross margin due to a lower of cost or market adjustment on oil inventory in 2020 . . . . . . . . . . . . . . . . . .
Lower gross margin from higher supply costs of $8.25 per MWh, or $78 million and lower volumes due to
attrition, weather and customer mix of $45 million, partially offset by higher revenue of $3 per MWh, or $29
million . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lower gross margin due to a 20% decrease in average realized pricing primarily at Midwest Generation . . . . . .
Lower gross margin due to the sale of fossil generating assets to Generation Bridge in December 2021 . . . . . . .
Lower gross margin from market optimization activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
939
73
29
(94)
(39)
(16)
(5)
Increase in economic gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1,033
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 amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,622
(54)
(200)
Increase in gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2,401
53
West/Services/Other
(In millions)
Higher gross margin due to Winter Storm Uri, driven by optimization during volatility in gas pricing . . . . . . . . . $
The following explanations exclude the impact of Winter Storm Uri:
Higher gross margin due to the acquisition of Direct Energy in January 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lower gross margin primarily at Cottonwood driven by an 83% increase in fuel cost, partially offset by a 41%
increase in realized power prices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lower gross margin primarily due to prior year MISO uplift payments resulting from out-of-market dispatch
during Hurricane Laura . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lower gross margin from generation outage insurance proceeds received in 2020 for forced outages in 2019,
partially offset by Sunrise business interruption proceeds received in 2021 for forced outages in 2019 . . . . . . . . .
Lower gross margin from market optimization activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lower gross margin due to the sale of fossil generating assets to Generation Bridge in December 2021 . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
13
425
(31)
(29)
(22)
(9)
(7)
7
Increase in economic gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
347
Increase in mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions
related to economic hedges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in contract amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in gross margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
19
(21)
(52)
293
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 $2.8 billion during the year ended December 31, 2021, compared to the
same period in 2020.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by segment was as
follows:
Year Ended December 31, 2021
(In millions)
Texas
East
West/
Services/
Other
Eliminations
Total
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains) on settled
positions related to economic hedges . . . . . . . . . . . . . . . . . . . . $
Reversal of acquired (gain) positions related to economic hedges
Net unrealized (losses) on open positions related to economic
hedges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
— $
(34) $
(4) $
—
(3)
(6)
(48)
—
(82)
Total mark-to-market (losses) in operating revenues . . . . . . . $
(3) $
(88) $
(86) $
(2) $
— $
15
13 $
(40)
(6)
(118)
(164)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains) on settled
positions related to economic hedges . . . . . . . . . . . . . . . . . . . . $
Reversal of acquired loss/(gain) positions related to economic
hedges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net unrealized gains on open positions related to economic
hedges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(3) $
— $
— $
2 $
(1)
42
949
235
1,568
(15)
117
—
262
(15)
(13) $
2,619
2,880
Total mark-to-market gains in operating costs and expenses $
988 $
1,803 $
102 $
54
Year Ended December 31, 2020
(In millions)
Texas
East
West/
Services/
Other
Eliminations
Total
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized losses/(gains) on
settled positions related to economic hedges . . . . . . . . . . . . . . $
Net unrealized gains on open positions related to economic
hedges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1 $
33 $
(7) $
1
55
4
Total mark-to-market gains/(losses) in operating revenues . . $
2 $
88 $
(3) $
4 $
4
8 $
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on
settled positions related to economic hedges . . . . . . . . . . . . . . $
(87) $
5 $
— $
(4) $
Reversal of acquired loss positions related to economic hedges. .
2
Net unrealized (losses) on open positions related to economic
hedges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(126)
2
(2)
—
—
—
(4)
31
64
95
(86)
4
(132)
Total mark-to-market (losses)/gains in operating costs and
expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(211) $
5 $
— $
(8) $
(214)
Mark-to-market results consist of unrealized gains and losses on contracts that are yet to be settled. The settlement of
these transactions is reflected in the same revenue or cost caption as the items being hedged.
The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date.
For the year ended December 31, 2021 the $164 million loss in operating revenues from economic hedge positions was
driven primarily by a decrease in the value of open positions as a result of increases in East and West/Services/Other power
prices, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period. The $2.9
billion 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 natural gas and power prices across all segments as well as the reversal of acquired
contracts that settled during the year.
For the year ended December 31, 2020 the $95 million gain in operating revenues from economic hedge positions was
driven primarily by an increase in the value of open positions as a result of decreases in New York capacity prices, as well as
the reversal of previously recognized unrealized losses on contracts that settled during the period. The $214 million loss in
operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions
as a result of decreases in ERCOT power prices and heat rate contraction, as well as the reversal of previously recognized
unrealized gains on contracts that settled during the period.
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, 2021 and 2020. 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)
Year ended December 31,
2021
2020
Realized . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
124
$
Unrealized . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total trading gains . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(32)
92
$
41
(5)
36
Operations and Maintenance Expenses
Operations and maintenance expenses are comprised of the following:
(In millions)
Texas
East
West/
Services/
Other
Corporate
Eliminations
Total
Year Ended December 31, 2021 . . . . . . . . . . . . . . . $
703 $
452 $
218 $
Year Ended December 31, 2020 . . . . . . . . . . . . . . .
651
371
104
2 $
9
(5) $
(6)
1,370
1,129
55
Operations and maintenance expenses increased by $241 million for the year ended December 31, 2021 compared to the
same period in 2020, due to the following:
(In millions)
Increase due to the acquisition of Direct Energy in January 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Increase in major maintenance primarily due to the duration and scope of planned and forced outages in Texas
during 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in variable operation and maintenance expense at the PJM coal facilities associated with increased
generation in 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase driven by higher maintenance resulting from the impacts of Winter Storm Uri . . . . . . . . . . . . . . . . . . . .
Decrease driven by lower retail operations costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Decrease in lease expense primarily driven by the buyout of the Midwest Generation lease in 2020 . . . . . . . . . .
Decrease due to the sale of fossil generating assets to Generation Bridge in December 2021 . . . . . . . . . . . . . . . .
Decrease due to prior year suspended plant project and prior year reserves for obsolete inventory . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in operations and maintenance expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
257
27
23
2
(29)
(16)
(11)
(9)
(3)
241
Other Cost of Operations
Other Cost of operations are comprised of the following:
(In millions)
Texas
East
West/Services/
Other
Total
Year Ended December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . $
Year Ended December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . .
194 $
163
129 $
91
16 $
18
339
272
Other cost of operations increased by $67 million for the year ended December 31, 2021 compared to the same period in
2020, due to the following:
Increase due to the acquisition of Direct Energy in January 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Decrease primarily due to ARO expense in 2020 at Jewett Mine and Joliet as a result of regulatory
requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in other cost of operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
83
(15)
(1)
67
(In millions)
Depreciation and Amortization
Depreciation and amortization expenses are comprised of the following:
(In millions)
Texas
East
West/Services/
Other
Corporate
Total
Year Ended December 31, 2021 . . . . . . . $
Year Ended December 31, 2020 . . . . . . .
331 $
227
338 $
138
88 $
36
28 $
34
785
435
Depreciation and amortization expense increased by $350 million for the year ended December 31, 2021 compared to the
same period in 2020, primarily due to amortization of acquired intangibles in connection with the acquisition of Direct Energy
in January 2021.
Impairment Losses
During the year ended December 31, 2021, the Company recorded impairment losses of $544 million, of which $306
million was recorded in the second quarter related to the decline in capacity prices and the planned retirement of a significant
portion of the PJM coal fleet, $213 million in the fourth quarter as a result of changes in the long-term outlook of the Joliet
facility prompted by market conditions and an assessment of various alternatives for the long-term operational landscape of the
facility including the impact of the CEJA in Illinois, and $25 million related to various other power plants. During the year
ended December 31, 2020, the Company recorded impairment losses of $75 million primarily related to the Cottonwood facility
and the Home Solar business. Refer to Item 15 — Note 11, Asset Impairments, to the Consolidated Financial Statements for
further discussion.
56
Selling, General and Administrative Costs
Selling, general and administrative costs are comprised of the following:
(In millions)
Texas
East
West/Services/
Other
Corporate
Total
Year Ended December 31, 2021 . . . . . . . $
Year Ended December 31, 2020 . . . . . . .
574 $
467
472 $
260
198 $
56
49 $
27
1,293
810
Selling, general and administrative costs increased by $483 million for the year ended December 31, 2021 compared to
the same period in 2020, due to the following:
Increase due to the acquisition of Direct Energy in January 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Increase due to Winter Storm Uri, including charitable giving, legal and other costs of $20 million and
ERCOT default charges of $9 million . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase due to higher consulting, service and insurance costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Decrease due to lower employee costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Decrease due to the favorable resolution of a legal matter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in selling, general and administrative costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(In millions)
460
29
26
(23)
(15)
6
483
Provision for Credit Losses
Provision for credit losses are comprised of the following:
(In millions)
Texas
East
West/Services/
Other
Total
Year Ended December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . $
Year Ended December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . .
678 $
94
8 $
14
12 $
—
698
108
Provision for credit losses increased by $590 million for the year ended December 31, 2021, compared to the same period
in 2020, due to the following:
Increase due to Winter Storm Uri, including:
Increase of $403 million related to bilateral financial hedging risk
Increase of $126 million related to counterparty credit risk
Increase of $67 million related to ERCOT default shortfall payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Decrease due to improved collections in the legacy brands, partially offset by the acquisition and integration
of Direct Energy in January 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in provision for credit losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(In millions)
596
(6)
590
Acquisition-Related Transaction and Integration Costs
Acquisition-related transaction and integration costs increased by $70 million when compared to the same period in 2020.
Acquisition-related transaction costs increased by $8 million, primarily related to the Direct Energy acquisition. Integration
costs increased by $62 million, primarily related to employee costs, software costs and consulting services for the Direct Energy
acquisition.
Gain on Sale of Assets
The gain on sale of assets of $247 million was recorded for the year ended December 31, 2021 includes a $210 million
gain on the sale of 4,850 MW of fossil generating assets in December 2021, a $20 million gain on the sale of a deactivated site
in November 2021, and a $17 million due to the sale of Agua Caliente in February 2021. The gain on the sale of assets of $3
million for the year ended December 31, 2020 was related to the sale of land and investments in January 2020, partially offset
by the disposition of the Home Solar business.
Impairment Losses on Investments
During the year ended December 31, 2020, the Company recorded other-than-temporary impairment losses on the
Company's investment in Petra Nova Parish Holdings of $18 million, as further described in Item 15 — Note 11, Asset
Impairments, to the Consolidated Financial Statements.
57
Loss on Debt Extinguishment
A loss on debt extinguishment of $77 million was recorded for the year ended December 31, 2021, driven by the
redemption of senior notes as further discussed in Item 15 — Note 13, Long-term Debt and Finance Leases, to the Consolidated
Financial Statements. A loss on debt extinguishment of $9 million was recorded for the year ended December 31, 2020, driven
by the debt extinguished in connection with the sale of Home Solar and the redemptions of the Indian River and Dunkirk bonds.
Interest Expense
Interest expense increased by $84 million for the year ended December 31, 2021 compared to the same period in 2020,
primarily due to financings entered into in connection with the Direct Energy acquisition.
Income Tax Expense
For the year ended December 31, 2021, NRG recorded income tax expense of $672 million on pre-tax income of $2.9
billion. For the same period in 2020, NRG recorded an income tax expense of $251 million on pre-tax income of $761 million.
The effective tax rate was 23.5% and 33.0% for the years ended December 31, 2021 and 2020, respectively.
For the year ended December 31, 2021, NRG's overall effective tax rate was higher than the federal statutory tax rate of
21% primarily due to state tax expense partially offset by tax benefits from the revaluation of state deferred tax assets,
valuation allowance, and settlements of uncertain tax positions.
(In millions, except effective income tax rate)
Year Ended December 31,
2020
2021
Income from continuing operations before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2,859
$
Tax at federal statutory tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign rate differential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred impact of state tax rate changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Permanent differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Return to provision adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Recognition of uncertain tax benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
600
(3)
111
(10)
(29)
8
5
(10)
761
160
—
18
2
24
8
36
3
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Effective income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
672
$
23.5 %
251
33.0 %
The effective income tax rate may vary from period to period depending on, among other factors, the geographic and
business mix of earnings and losses and changes in valuation allowances in accordance with ASC 740, 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.
Liquidity and Capital Resources
Liquidity Position
As of December 31, 2021 and 2020, NRG's liquidity, excluding collateral funds deposited by counterparties, was
approximately $2.7 billion and $7.0 billion, respectively, comprised of the following:
(In millions)
Cash and cash equivalents: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Restricted cash - operating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted cash - reserves (a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total availability under Revolving Credit Facility and collective collateral facilities(b)
. . . . . . . .
Total liquidity, excluding collateral funds deposited by counterparties . . . . . . . . . . . . . . . . . . . $
As of December 31,
2021
2020
250 $
4
11
265
2,421
2,686 $
3,905
3
3
3,911
3,129
7,040
Includes reserves primarily for debt service, performance obligations and capital expenditures
(a)
(b) Total capacity of Revolving Credit Facility and collective collateral facilities was $5.9 billion and $4.0 billion as of December 31, 2021 and December 31,
2020, respectively
58
As of December 31, 2021, total liquidity, excluding collateral funds deposited by counterparties, decreased by $4.4
billion. The decrease was primarily driven by the closing of the Direct Energy acquisition and the impact of Winter Storm Uri.
Changes in cash and cash equivalent balances are further discussed under the heading Cash Flow Discussion. Cash and cash
equivalents at December 31, 2021 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 March 17, 2021, following Winter Storm Uri, Standard & Poor's placed NRG's issuer credit rating of BB+ on
CreditWatch with negative implications. On May 12, 2021, Standard & Poor's affirmed NRG's issuer credit rating of BB+ with
a stable outlook. On March 19, 2021, Moody's changed NRG's rating outlook from positive to stable. At the same time,
Moody's affirmed NRG's corporate family rating of Ba1.
The following table summarizes the Company's current credit ratings:
NRG Energy, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.75% Senior Secured Notes, due 2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.00% Senior Secured Notes, due 2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.45% Senior Secured Notes, due 2027 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.625% Senior Notes, due 2027 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.75% Senior Notes, due 2028 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.375% Senior Notes, due 2029 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.45% Senior Secured Notes, due 2029 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
5.25% Senior Notes, due 2029 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.625% Senior Notes, due 2031 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.875% Senior Notes, due 2032 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revolving Credit Facility, due 2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
S&P
BB+ Stable
BBB-
BBB-
BBB-
BB+
BB+
BB+
BBB-
BB+
BB+
BB+
BBB-
Moody's
Ba1 Stable
Baa3
Baa3
Baa3
Ba2
Ba2
Ba2
Baa3
Ba2
Ba2
Ba2
Baa3
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 and financing arrangements. As described in Item 15 — Note 13, Long-term Debt and
Finance Leases, to the Consolidated Financial Statements, the Company's financing arrangements consist mainly of the Senior
Notes, Convertible Senior Notes, Senior Secured First Lien Notes, Revolving Credit Facility, and tax-exempt bonds.
The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be
categorized by the following: (i) market operations activities; (ii) debt service obligations, as described more fully in
Item 15 — Note 13, Long-term Debt and Finance Leases, to the Consolidated Financial Statements; (iii) capital expenditures,
including maintenance, repowering, development, and environmental; and (iv) allocations in connection with acquisition
opportunities, debt repayments, share repurchases and dividend payments to stockholders, as described in Item 15 — Note 16,
Capital Structure, to the Consolidated Financial Statements.
Direct Energy Acquisition
On January 5, 2021, the Company acquired Direct Energy, which had been a North American subsidiary of Centrica.
Direct Energy is a leading retail provider of electricity, natural gas, and home and business energy related products and services
in North America, with operations in all 50 U.S. states and 8 Canadian provinces.
The Company paid an aggregate purchase price of $3.625 billion in cash, subject to a purchase price adjustment of
$77 million. The Company funded the purchase price using a combination of $715 million of cash on hand, $166 million from a
draw on its Revolving Credit Facility (of which $107 million was used to fund acquisition costs and financing fees that are not
included in the aggregate purchase price above) as well as approximately $2.9 billion in secured and unsecured corporate debt
issued in December 2020. The final purchase price adjustment resulted in additional payment of $22 million, which was paid to
Centrica in December 2021.
59
Collateral Facility Increases
The following table presents increases to the Company's liquidity and collateral facilities in connection with the Direct
Energy acquisition:
Available on Acquisition Closing Date
(In millions)
Revolving Credit Facility commitment increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Revolving Credit Facility new tranche . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Facility agreement in connection with the sale of pre-capitalized trust securities . . . . . . . . . . . . . . . . . . . . .
Available as of December 31, 2020
Credit default swap facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revolving accounts receivable financing facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repurchase facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Bilateral letter of credit facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
802
273
874
150
750
75
475
Total Increases to Liquidity and Collateral Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
3,399
Planned Debt Reduction
In light of the impact of Winter Storm Uri, the Company's deleveraging program will extend to 2023. The Company
remains committed to maintaining a strong balance sheet and continues to work to achieve investment grade credit metrics.
Issuance of 2032 Senior Notes
On August 23, 2021, the Company issued $1.1 billion of aggregate principal amount at par of 3.875% senior notes due
2032 (the "2032 Senior Notes"). The 2032 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain
of its subsidiaries. The 2032 Senior Notes were issued under NRG's Sustainability-Linked Bond Framework, which sets out
certain sustainability targets, including reducing greenhouse gas emissions. Failure to meet such sustainability targets will result
in a 25 basis point increase to the interest rate payable on the 2032 Senior Notes from and including August 15, 2026.
Senior Note Redemptions
During the year ended December 31, 2021, the Company redeemed $1.9 billion in aggregate principal of its Senior Notes
for $1.9 billion using the proceeds of the 2032 Senior Notes and cash on hand. In connection with the redemptions, a
$77 million loss on debt extinguishment was recorded.
Receivables Facility
On July 26, 2021, NRG Receivables LLC, a wholly-owned indirect subsidiary of the Company, renewed its existing
accounts receivable securitized borrowings facility (the "Receivables Facility") to, among others, (i) increase the facility size to
$800 million, (ii) extend the maturity date until July 26, 2022, (iii) make certain adjustments to the pool of receivables through
the Receivables Facility and certain related covenants, and (iv) provide for revised language relating to interest determination
based on SOFR in case of a LIBOR cessation or the occurrence of certain other trigger events. As of December 31, 2021, there
were no outstanding borrowings and there were $400 million in letters of credit issued under the Receivables Facility.
Repurchase Facility
On July 26, 2021, the Company renewed its existing uncommitted repurchase facility ("Repurchase Facility") to, among
other things, (i) extend the maturity date to July 26, 2022 and (ii) provide for revised language relating to interest determination
based on SOFR in case of a LIBOR cessation or the occurrence of certain other trigger events. On February 9, 2022, the
Company entered into amendments to its existing Repurchase Facility to, among other things, (i) increase the size of the facility
from $75 million to $150 million and (ii) replace LIBOR with term SOFR as the benchmark for the pricing rate. The
Repurchase Facility has no commitment fee and borrowings will be drawn at SOFR + 1.30%. As of December 31, 2021, there
were no outstanding borrowings under the Repurchase Facility.
Sale of 4.8 GW of Fossil Generation Assets
On December 1, 2021, the Company closed the previously announced sale of approximately 4,850 MWs of fossil
generating assets from its East and West regions to Generation Bridge, an affiliate of ArcLight Capital Partners. At Closing,
NRG received $623 million of net proceeds, after working capital and other adjustments, including a deduction for cash flows
generated of approximately $11 million per month from the beginning of the year until the closing of the transaction, in lieu of
60
cash flows generated during the year. As part of the transaction, NRG entered into a tolling agreement for the 866 MW Arthur
Kill plant in New York City through April 2025.
Sale of Agua Caliente
On February 3, 2021, the Company closed on the sale of its 35% ownership in the Agua Caliente solar project to
Clearway Energy, Inc. for $202 million. NRG recognized a gain on the sale of $17 million, including cash disposed of
$7 million.
CARES Act
On March 27, 2020, the U.S. government enacted the CARES Act, which provides, among other things: (i) the option to
defer payments of certain 2019 employer payroll taxes incurred after the date of enactment; and (ii) allows NOLs from tax
years 2018, 2019, and 2020 to be carried back five years. The total benefit to the Company due to the CARES Act was $35
million. Of this amount, $13 million was paid to social security in 2021 and $13 million will be payable in 2022.
Pension Plan Contribution
The American Rescue Plan Act ("ARPA") was enacted on March 11, 2021 to provide economic relief related to the
COVID-19 pandemic. ARPA provided pension funding relief for single employer plans, among other provisions. As a result,
NRG reduced its 2021 planned cash contribution by approximately $23 million.
Pension and Other postretirement benefits minimum funding requirements
As of December 31, 2021, the Company does not have estimated minimum pension contributions required under the
Pension Protection Act of 2006 for the next 5 years. As of December 31, 2021, the Company’s estimated Other postretirement
benefits minimum funding requirements for the next 5 years were $33 million, of which $7 million are required to be made
within the next 12 months. These amounts represent estimates based on assumptions that are subject to change. For further
discussion, see Item 15 — Note 15, Benefit Plans and Other Postretirement Benefits, to the Consolidated Financial Statements.
Debt Service Obligations
Principal payments on debt and finance leases as of December 31, 2021 are due in the following periods:
(In millions)
Description
Recourse Debt:
2022
2023
2024
2025
2026
Thereafter
Total
Senior notes, due 2027 . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ — $ — $ — $ — $
375 $
Senior notes, due 2028 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior notes, due 2029 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior notes, due 2029 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior notes, due 2031 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior Notes, due 2032 . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Convertible Senior Notes, due 2048 . . . . . . . . . . . . . . . . . .
Senior Secured First Lien Notes, due 2024 . . . . . . . . . . . .
Senior Secured First Lien Notes, due 2025 . . . . . . . . . . . .
Senior Secured First Lien Notes, due 2027 . . . . . . . . . . . .
Senior Secured First Lien Notes, due 2029 . . . . . . . . . . . .
Tax-exempt bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal Recourse Debt . . . . . . . . . . . . . . . . . . . . . . . .
Finance Leases: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Finance leases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal Finance Leases . . . . . . . . . . . . . . . . . . . . . . . .
—
—
—
—
—
—
—
—
—
—
—
—
4
4
—
—
—
—
—
—
—
—
—
—
—
—
3
3
—
—
—
—
—
—
600
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
500
—
—
—
—
—
—
—
375
821
733
500
821
733
500
1,030
1,030
1,100
1,100
575
—
—
900
500
466
575
600
500
900
500
466
600
500
—
7,000
8,100
3
3
2
2
—
—
1
1
13
13
Total Debt and Finance Leases . . . . . . . . . . . . . . . . . . $
4 $
3 $
603 $
502 $ — $
7,001 $ 8,113
Interest Payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
385 $
383 $
363 $
352 $ 334 $
1,224 $ 3,041
For further discussion, see Item 15 — Note 13, Long-term Debt and Finance Leases.
61
Market Operations
The Company's market 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); and (iv) initial collateral for large structured transactions. As of December 31, 2021, market
operations had total cash collateral outstanding of $291 million and $3.5 billion outstanding in letters of credit to third parties
primarily to support its market activities. As of December 31, 2021, total funds deposited by counterparties were $845 million
in cash and $429 million of letters of credit.
The Company has entered into long-term contractual arrangements to procure certain fuel and transportation services for
the Company's generation assets. As of December 31, 2021, the Company had minimum payment obligations under such
outstanding agreements of $378 million, with $122 million payable within the next 12 months. Additionally, the Company has
long-term contractual commitments related to electricity and natural gas products, including power purchases, gas
transportation and storage of various quantities and durations, and renewable purchased power agreements under PPAs with
third-party project developers, which are accounted for as NPNS. As of December 31, 2021, the Company had minimum
purchased energy commitments of $5.0 billion, with $1.6 billion payable within the next 12 months. For further discussion, see
Item 15 — Note 23, Commitments and Contingencies.
Future liquidity requirements may change based on the Company's hedging activities and structures, fuel purchases, and
future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements
are dependent on the Company's credit ratings and general perception of its creditworthiness.
First Lien Structure
NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, subject to various
exclusions including NRG's assets that have project-level financing and the assets of certain non-guarantor subsidiaries, 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 first lien
program does not limit the volume that can be hedged or the value of underlying out-of-the-money positions. The first lien
program also does not require NRG to post collateral above any threshold amount of exposure. 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, 2021, all hedges under the first liens were out-of-the-money on a counterparty aggregate basis.
The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a
percentage relative to the Company's coal and nuclear capacity under the first lien structure as of December 31, 2021:
Equivalent Net Sales Secured by First Lien Structure (a)
In MW . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As a percentage of total net coal and nuclear capacity (b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2022
653
15%
2023
738
17%
(a) Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region
(b) Net coal and nuclear capacity represents 80% of the Company's total coal and nuclear assets eligible under the first lien, which excludes coal assets
acquired in the Midwest Generation acquisition
Capital Expenditures
The following table summarizes the Company's capital expenditures for maintenance, environmental, and growth
investments for the year ended December 31, 2021:
(In millions)
Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
East . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
West/Services/Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Corporate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total cash capital expenditures for 2021 . . . . . . . . . . . . . . . . . . . .
Investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total capital expenditures and investments . . . . . . . . . . . . . . . . . . . . . . . $
(a)
Includes other investments, acquisitions, digital NRG and integration projects
62
Maintenance
Environmental
Growth
Investments(a)
Total
(127) $
(23)
(21)
(4)
(175)
—
(175) $
(1) $
(1)
—
—
(2)
—
(2) $
(25) $
(26)
—
(41)
(92)
(47)
(139) $
(153)
(50)
(21)
(45)
(269)
(47)
(316)
Growth investments in East for the year ended December 31, 2021 include the Astoria generating facility, for which the
Company has proposed to replace existing units with a single, new state-of-the-art Simple Cycle Combustion Turbine having a
total generating capacity of 437 MW. On October 27, 2021, the NYSDEC Staff denied the Company's application for an air
permit. On November 26, 2021, Astoria Gas Turbine Power LLC filed a Request for Adjudicatory Hearing on the NYSDEC's
denial. To date, the Company has spent approximately $42 million on the Astoria project. Additionally, included in Investments
are expenditures for Encina site improvements classified as ARO payments. Demolition of Encina is underway and is expected
to be completed in the first half of 2022. The Company expects to begin marketing the site in 2022.
Environmental Capital Expenditures Estimate
NRG estimates that environmental capital expenditures from 2022 through 2026 required to comply with environmental
laws will be approximately $56 million. The largest component is the cost of complying with ELG at our coal units in Texas.
The table below summarizes the status of NRG's coal fleet with respect to air quality controls. NRG uses an integrated
approach to fuels, controls and emissions markets to meet environmental requirements.
Units
State
Control
Equipment
Install
Date
Control
Equipment
Install
Date
Control
Equipment
Install
Date
Control
Equipment
Install Date
SO2
NOx
Mercury
Particulate
2011
LNBOFA/
SCR
1999/2011
ACI/CDS/FF
2008/2011
ESP/FF
Indian River 4 . . . . . .
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
TX
IL
IL
TX
TX
IL
IL
IL
CDS
FGD
DSI
DSI
FF co-
benefit
FGD
DSI
DSI
DSI
ACI - Activated Carbon Injection
CDS - Circulating Dry Scrubber
DSI - Dry Sorbent Injection with Trona
ESP - Electrostatic Precipitator
FGD - Flue Gas Desulfurization (wet)
1985-86
LNBOFA
2002/2003
OFA/SNCR
2003/2012
OFA/SNCR
2002/2012
2016
2014
1988
1982
SCR
SCR
2014
LNBOFA
2015
LNBOFA
2004
2004
2002
1999
2017
LNBOFA
1999,2000
ACI
ACI
ACI
ACI
ACI
ACI
ACI
ACI
ESP/upgrade
1973/2016
ESP/upgrade
1976/2014
2015
2009
2009
2015
2015
ESP
FF
FF
2008
ESP/upgrade
2008
ESP/upgrade
2009
ESP/upgrade
1980/2011
1985-1986
1988
1988
1958/2002,
2014
1962/1999,
2015
1963,72/
2000
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 by year:
(In millions)
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
Total
8
1
22
22
3
56
63
Share Repurchases
In December 2021, the Company's board of directors authorized the Company to repurchase $1.0 billion of its common
stock. Through December 31, 2021, the Company completed $53 million of share repurchases at an average price of $40.22 per
share, including $9 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances.
Through February 24, 2022, an additional $82 million of share repurchases were executed at an average price of $40.26 per
share, including $6 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances. See
Item 15 - Note 16, Capital Structure, to the Consolidated Financial Statements for additional discussion.
Dividend Increase
In the first quarter of 2021, NRG increased the annual dividend to $1.30 from $1.20 per share. The Company returned
$320 million of capital to shareholders in the year ended 2021 through a $1.30 dividend per common share. In 2022, NRG
further increased the annual dividend to $1.40 per share, representing an 8% increase from 2021. The Company expects to
target an annual dividend growth rate of 7-9% per share in subsequent years.
On January 21, 2022, NRG declared a quarterly dividend on the Company's common stock of $0.35 per share, or $1.40
per share on an annualized basis, payable on February 15, 2022, to stockholders of record as of February 1, 2022. The
Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws
and regulations.
Additional Material Cash Requirements Not Discussed Above
Operating leases — The Company leases generating facilities, land, office and equipment, railcars, fleet vehicles and
storefront space at retail stores. As of December 31, 2021, the Company had lease payment obligations of $372 million, of
which $96 million is payable within the next 12 months. For further discussion, see Item 15 — Note 10, Leases.
Other liabilities — Other liabilities includes water right agreements, service and maintenance agreements, stadium
naming rights, stadium sponsorships, LTSA commitments and other contractual obligations. As of December 31, 2021, the
Company had total of $210 million under such commitments, of which $41 million are payable within the next 12 months.
Contingent obligations for guarantees — NRG and its subsidiaries enter into various contracts that include
indemnifications and guarantee provisions as a routine part of the Company’s business activities. For further discussion, see
Item 15 —Note 27, Guarantees.
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity
Variable interest in Equity investments — As of December 31, 2021, 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. Ivanpah 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 $535 million as of
December 31, 2021. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG.
See also Item 15 — Note 17, Investments Accounted for by the Equity Method and Variable Interest Entities, to the
Consolidated Financial Statements for additional discussion.
Cash Flow Discussion
2021 compared to 2020
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)/provided by financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year ended December 31,
2021
2020
Change
493
$
1,837
$
(3,039)
(272)
(494)
2,204
(1,344)
(2,545)
(2,476)
64
Net Cash (Used)/Provided By Operating Activities
Changes to net cash (used)/provided by operating activities were driven by:
Decrease in working capital related to accounts receivable primarily driven by milder weather in 2020, the
impact of Winter Storm Uri and additional early settlement of capacity obligations in 2021 . . . . . . . . . . . . . . . . . $
Decrease in operating income adjusted for other non-cash items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in cash collateral in support of risk management activities due to change in commodity prices . . . . . . .
Increase in working capital related to accounts payable primarily driven by increases in gas purchases and
bilateral physical settlements driven by price and volume in ERCOT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Decrease in working capital related to inventory due to replenishing natural gas inventory at significantly higher
prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other changes in working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(1,232)
(1,235)
670
532
(88)
9
(In millions)
Net Cash (Used)/Provided By Investing Activities
Changes to net cash (used)/provided by investing activities were driven by:
$
(1,344)
(In millions)
Increase in cash paid for acquisitions of assets primarily for Direct Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(3,275)
Increase in proceeds from sale of assets primarily due to the fossil generating assets and Agua Caliente . . . . . . .
Decrease in capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in proceeds from sales of investments in nuclear decommissioning trust fund securities, net of
purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in sales of emissions allowances, net of purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Cash (Used)/Provided By Financing Activities
Changes in net cash (used)/provided by financing activities were driven by:
749
(39)
12
10
(2)
$
(2,545)
(In millions)
Decrease in proceeds from issuance of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Increase in payments of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in net receipts from settlement of acquired derivatives
Decrease in payments for share repurchase activity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in proceeds from Revolving Credit Facility and Receivables Securitization Facilities
Increase in payments of dividends to common stockholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(2,134)
(1,526)
945
181
83
(24)
(1)
$
(2,476)
NOLs, Deferred Tax Assets and Uncertain Tax Position Implications
For the year ended December 31, 2021, the Company had domestic pre-tax book income of $2.8 billion and foreign pre-
tax book income of $100 million. For the year ended December 31, 2021, the Company utilized U.S. federal NOLs of
$1.6 billion due to current year taxable income. As of December 31, 2021, the Company has cumulative U.S. federal NOL
carryforwards of $8.4 billion, of which $11 million were generated prior to Tax Cuts and Jobs Act and will begin expiring in
2031 and cumulative state NOL carryforwards of $5.2 billion for financial statement purposes. NRG also has cumulative
foreign NOL carryforwards of $383 million, which do not have an expiration date. In addition to the above NOLs, NRG has a
$20 million indefinite carryforward for interest deductions, as well as $384 million of tax credits to be utilized in future years.
As a result of the Company's tax position, including the utilization of federal and state NOLs, and based on current forecasts,
the Company anticipates income tax payments, due to federal, state and foreign jurisdictions, of up to $58 million in 2022.
65
The Company has $13 million of tax effected uncertain federal and state tax benefits for which the Company has recorded
a non-current tax liability of $14 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 2018. With few exceptions,
state and Canadian income tax examinations are no longer open for years before 2013.
Guarantor Financial Information
As of December 31, 2021, the Company's outstanding registered senior notes consisted of $375 million of the 2027 Senior
Notes and $821 million of the 2028 Senior Notes, as shown in Note 13, Long-term Debt and Finance Leases. These Senior
Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries (the
“Guarantors”). See Exhibit 22.1 for a listing of the Guarantors. These guarantees are both joint and several.
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. There are no restrictions on the
ability of any of the Guarantors to transfer funds to NRG. Other subsidiaries of the Company do not guarantee the registered
debt securities of either NRG Energy, Inc. or the Guarantors (such subsidiaries are referred to as the “Non-Guarantors”). The
Non-Guarantors include all of NRG's foreign subsidiaries and certain domestic subsidiaries.
The tables below present summarized financial information of NRG Energy, Inc. and the Guarantors 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 of NRG Energy, Inc. and the Guarantors in accordance with U.S. GAAP.
The following table presents the summarized statement of operations:
For the Year Ended
December 31, 2021(a)
23,679
(In millions)
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total other expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from continuing operations before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,753
(467)
3,286
2,633
(a)
Intercompany transactions with Non-Guarantors include operating revenue of $42 million, cost of operations of $(235) million and selling, general and
administrative of $108 million
The following table presents the summarized balance sheet information:
(In millions)
Current assets(a)
Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
December 31, 2021
Non-current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current liabilities(a)
Non-current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(a)
Includes intercompany receivables of $86 million and intercompany payables of $50 million due from Non-Guarantors
9,399
1,324
11,569
7,590
11,195
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 power
plants or retail load obligations. In addition, in order to mitigate foreign exchange rate risk primarily associated with the
purchase of USD denominated natural gas for the Company's Canadian business, NRG enters into foreign exchange contract
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.
66
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, 2021, based on
their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at December 31, 2021.
For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in
Item 15 — Note 5, Fair Value of Financial Instruments, to the Consolidated Financial Statements.
Derivative Activity (Losses)/Gains
(In millions)
Fair value of contracts as of December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Contracts realized or otherwise settled during the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Contracts acquired from Direct Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value of contracts as of December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(63)
190
(283)
2,497
2,341
(In millions)
Fair value hierarchy Gains
Fair Value of Contracts as of December 31, 2021
Maturity
1 Year or Less
Greater Than 1
Year to 3 Years
Greater Than 3
Years to 5
Years
Greater Than
5 Years
Total Fair
Value
Level 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
134 $
192 $
23 $
6 $
Level 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Level 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
941
151
645
82
82
16
25
44
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1,226 $
919 $
121 $
75 $
355
1,693
293
2,341
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, 2021, NRG's net derivative asset was $2.3 billion, an increase to total fair value of
$2.4 billion as compared to December 31, 2020. This increase was primarily driven by roll-off trades that settled during the
period, as well as gains in fair value.
Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas
prices across the term of the derivative contracts would result in an increase of approximately $1.3 billion in the net value of
derivatives as of December 31, 2021.
The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of the derivative contracts would result in
a decrease of approximately $1.4 billion in the net value of derivatives as of December 31, 2021.
Critical Accounting Estimates
The Company'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 appropriate technical accounting rules
and guidance 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 accounting guidance has not changed.
67
NRG evaluates these estimates, on an ongoing basis, 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.
The Company identifies its most critical accounting estimates as those that are the most pervasive and important to the
portrayal of the Company's financial position and results of operations, and require the most difficult, subjective, and/or
complex judgments by management about matters that are inherently uncertain.
Such accounting estimates include:
Accounting Estimate
Derivative Instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Assumptions used in valuation techniques
Judgments/Uncertainties Affecting Application
Assumptions used in forecasting generation and retail load
Market maturity and economic conditions
Contract interpretation
Market conditions in the energy industry, especially the
effects of price volatility on contractual commitments
Income Taxes and Valuation Allowance for Deferred Tax Assets . Ability to be sustained upon audit examination of taxing
Evaluation of Assets for Impairment and Other-Than-Temporary
Decline in Value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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
Goodwill and Other Intangible Assets . . . . . . . . . . . . . . . . . . . . . . . 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
Business Combinations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fair value of assets acquired and liabilities assumed in
business combinations
Estimated future cash flow
Estimated useful lives of assets
Contingencies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Estimated financial impact of event(s)
Judgment about likelihood of event(s) occurring
Regulatory and political environments and requirements
Derivative Instruments
The Company follows the guidance of ASC 815, Derivatives and Hedging, or 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
fair value change in earnings, unless they qualify for the NPNS exception. ASC 815 applies to NRG's energy related
commodity contracts, interest rate swaps and foreign exchange contracts.
For purposes of measuring the fair value of derivative instruments, the Company 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. These estimations are considered to be critical accounting estimates.
68
During the fourth quarter of 2020, the Company entered into $1.6 billion of interest rate hedges associated with
anticipated certain financing needs. As of December 31, 2020, the interest rate hedges were settled in connection with the
issuance of fixed rate debt, resulting in a gain of $11 million that was recorded as a reduction to interest expense. In order to
qualify the derivative instruments for hedged transactions prior to termination, NRG estimated the forecasted borrowings for
interest rate swaps occurring within a specified time period.
In order to mitigate foreign exchange risk primarily associated with the purchase of USD denominated natural gas for the
Company's Canadian business, the Company enters into foreign exchange contract agreements.
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 the Company has the ability and it is probable to deliver or take delivery of the underlying item. These assumptions are
based on expected load requirements, 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, 2021, NRG’s deferred tax assets were primarily the result of U.S. federal and state NOLs, the
difference between book and tax basis in property, plant, and equipment, and tax credit carryforwards. The realization of
deferred tax assets is dependent upon the Company's ability to generate sufficient future taxable income during the periods in
which those temporary differences become deductible, prior to the expiration of the tax attributes. The evaluation of deferred
tax assets requires judgment in assessing the likely future tax consequences of events that have been recognized in the
Company's financial statements or tax returns and forecasting future profitability by tax jurisdiction.
The Company evaluates its deferred tax assets quarterly on a jurisdictional basis to determine whether adjustments to the
valuation allowance are appropriate considering changes in facts or circumstances. As of each reporting date, management
considers new evidence, both positive and negative, when determining the future realization of the Company’s deferred tax
assets. Given the Company’s current level of pre-tax earnings and forecasted future pre-tax earnings, the Company expects to
generate income before taxes in the U.S. in future periods at a level that would fully utilize its U.S. federal NOL carryforwards
and the majority of its state NOL carryforwards prior to their expiration.
The Company continues to maintain a valuation allowance of approximately $248 million as of December 31, 2021
against deferred tax assets consisting of state net operating losses and foreign NOL carryforwards in jurisdictions where the
Company does not currently believe that the realization of deferred tax assets is more likely than not. As of December 31, 2020
the Company's valuation allowance balance was $266 million.
Considerable judgment is required to determine the tax treatment of a particular item that involves interpretations of
complex tax laws. The Company 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 and Canada. The Company
continues to be under audit for multiple years by taxing authorities in various jurisdictions.
The Company is no longer subject to U.S. federal income tax examinations for years prior to 2018. With few exceptions,
state and and Canadian income tax examinations are no longer open for years before 2013.
NRG does not intend, nor currently foresee a need, to repatriate funds held at our international operations into the U.S.
These funds are deemed to be indefinitely reinvested in our foreign operations and the Company has not changed its assertion
with respect to distributions of funds that would require the accrual of U.S. income tax.
69
Evaluation of Assets for Impairment and Other-Than-Temporary Decline in Value
In accordance with ASC 360, Property, Plant, and Equipment, or ASC 360, the Company evaluates property, plant and
equipment and certain intangible assets for impairment whenever indicators of impairment exist. Examples of such indicators or
events include:
•
•
•
•
•
•
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 amounts originally expected for the construction or acquisition of
an asset;
Current period loss combined with a history of losses or the projection of future losses; and
Change in the Company's intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will
be sold, or disposed of before the end of its previously estimated useful life.
Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future
net cash flows expected to be generated by the asset, through considering project specific assumptions for long-term power and
natural gas 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, 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. The Company considers quoted market prices in active markets to the extent they are available. In the
absence of such information, NRG may consider prices of similar assets, consult with brokers, or employ other valuation
techniques. The Company 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 asset. 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 NRG's estimates and the impact of such variations could be material.
During the second quarter of 2021, the results of the PJM Base Residual Auction for the 2022/2023 delivery year were
released leading the Company to announce the near-term retirement of a significant portion of its PJM coal generating assets in
June 2022. The Company considered the decline in PJM capacity prices and the near-term retirement dates of certain assets to
be a trigger for impairment and performed impairment tests on the PJM generating assets and the goodwill associated with
Midwest Generation. The Company measured the impairment losses on the PJM generation assets and Midwest Generation
goodwill as the difference between the carrying amount and the fair value of the PJM generating assets and Midwest
Generation reporting unit, respectively. Fair values were determined primarily using an income approach in which the
Company applied a discounted cash flow methodology to the long-term budgets for the plants and reporting unit. Significant
inputs impacting the income approach include the Company's long-term view of capacity and fuel prices, projected generation,
the physical and economic characteristics of each plant, and the discount rate applied to the after-tax cash flow projections.
Impairment losses of $271 million and $35 million were recorded in the East segment on the PJM generating assets and
Midwest Generation goodwill, respectively.
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 impact 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.
In the fourth quarter of 2021, the Company recognized an impairment loss of $213 million in the East segment as a result
of changes in the long-term outlook of the Joliet facility prompted by market conditions and an assessment of various
alternatives for the long-term operational landscape of the facility including the impact of the CEJA in Illinois, which concluded
with the annual budget process. The Company recorded additional impairment losses of $16 million and $9 million related to
various power plants in the East and West/Services/Other segments, respectively.
70
In the third quarter of 2020, the Company concluded its Home Solar business was held for sale as a result of advanced
negotiations to sell the business and recorded an impairment loss of $29 million in the West/Services/Other segment to adjust
the carrying amount of the assets and liabilities to fair market value based on indicative sale prices. On November 13, 2020, the
Company completed the sale of the Home Solar business for $66 million.
In the fourth quarter of 2020, the Company recognized an impairment loss of $32 million in the West/Services/Other
segment related to the Cottonwood facility. The impairment was attributable to the Company's long-term services agreement
and related lease payments, as the carrying amounts of the assets from the contract were higher than the estimated operating
cash flow though the remaining lease period. Additionally, in the fourth quarter of 2020, the Company recorded $14 million of
impairment losses related to intangible assets in the Texas segment.
Equity Method Investments
The Company is also required to evaluate for impairment its equity method investments 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 an observed decline in the value of an equity method investment is considered other-than-
temporary. 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
the Company makes with respect to its equity 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, the Company 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 first quarter of 2020, NRG recorded an
impairment loss of $18 million in the Texas segment, attributable to its equity method investment in Petra Nova Parish
Holdings, which included the anticipated drawdown of the $12 million letter of credit posted in September 2019 to cover
certain project debt reserve requirements.
Goodwill and Other Intangible Assets
At December 31, 2021, the Company reported goodwill of $1.8 billion, consisting of $1.3 billion from the acquisition of
Direct Energy in 2021, $130 million associated with the acquisition of Midwest Generation and $414 million for retail
operations acquisitions, including Stream Energy, which was acquired in 2019.
The Company applies ASC 805, Business Combinations, or ASC 805, and ASC 350, Intangibles-Goodwill and Other, or
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 fair value of the
reporting unit may be below the carrying amount. 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, the Company's goodwill will be impaired at that time.
During the second quarter of 2021, the results of the PJM Base Residual Auction for the 2022/2023 delivery year were
released leading the Company to announce the near-term retirement of a significant portion of its PJM coal generating assets in
June 2022. The Company considered the decline in PJM capacity prices and the near-term retirement dates of certain assets to
be a trigger for impairment and performed impairment tests on the PJM generating assets and the goodwill associated with
Midwest Generation. An impairment of $35 million was recorded in Midwest Generation goodwill. For further discussion, see
Evaluation of Assets for Impairment and Other-Than-Temporary Decline in Value caption above.
During the fourth quarter of 2021, the Company performed its qualitative assessment of macroeconomic, industry and
market events and circumstances, and the overall financial performance of the Texas (Texas segment) and East Retail (East
segment) 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, 2021.
71
During the fourth quarter of 2021, the Company also performed a quantitative assessment for the Midwest Generation
(East segment) and West/Services/Other reporting units. The Company determined the fair value of the reporting units using an
income approach. Based on the income approach, the Company estimated the fair value of each reporting units' cash flows
exceeded its carrying value and, as such, NRG concluded that the goodwill associated with each reporting unit was not
impaired as of December 31, 2021.
The Company believes the methodology and assumptions used in its quantitative assessments were consistent with the
views of market participants. Significant inputs to the determinations of fair value of the Midwest Generation reporting unit
were as follows:
•
The Company applied a discounted cash flow methodology to the long-term budgets for the Midwest Generation
plants, resulting in fair value over the carrying value of the reporting unit of 117%. 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, capacity and fuel prices consider market prices for the next five years 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 prices and heat rate that
would support new build of a combined cycle gas plant. The price of natural gas plays an important role in
setting the price of electricity in many of the regions where NRG operates power plants. Hedging is included
to the extent of contracts already in place;
The Company's estimate of generation, fuel costs, capital expenditure requirements and the existing and
anticipated impact of environmental regulations;
The Company's fundamental view for the longer term, cash flows for the plants in the region were included in
the fair value calculation through the end of each plants' estimated useful life; and
Projected generation and resulting energy gross margin in the long-term budgets is based on an hourly
dispatch that simulates dispatch of each unit into the power market. The dispatch simulation is based on
power prices, fuel prices, and the physical and economic characteristics of each plant.
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.
Business Combinations
We account for business acquisitions using the acquisition method of accounting prescribed under ASC 805. Under this
method, we are required to record on our Consolidated Balance Sheets the estimated fair values of the acquired company’s
assets and liabilities assumed at the acquisition date. The excess of the consideration transferred over the fair value of the net
identifiable assets acquired and liabilities assumed is recorded as goodwill. Determining fair values of assets acquired and
liabilities assumed requires significant estimates and judgments. We determine fair value based on the estimated price that
would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the
measurement date. The acquired assets and assumed liabilities that involved the most subjectivity in determining fair value
consisted of the trade names, customer relationships and derivative contracts.
The fair value of trade names and customer relationships was measured using income-based valuation methodologies,
which include certain assumptions such as forecasted future cash flows, customer attrition rates, royalty rates and discount
rates. The trade names are amortized to depreciation and amortization, on a straight line basis. The customer relationships are
amortized to depreciation and amortization, ratably based on discounted future cash flows.
In measuring the fair value of derivative contracts, a significant portion of the fair value of the derivative portfolio was
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 were 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.
The fair value of each contract was discounted using a risk free interest rate. In addition, the Company applied a credit reserve
to reflect credit risk. NRG describes in detail its acquisitions in Item 15 — Note 4, Acquisitions, Discontinued Operations and
Dispositions, to the Consolidated Financial Statements
72
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 23, 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.
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 operations, merchant power generation, or with an
existing or forecasted financial or commodity transactions. 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 other
exchanges, and swaps and options traded in the over-the-counter financial markets to:
• Manage and hedge fixed-price purchase and sales commitments;
•
•
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 load servicing obligations and merchant generation operations 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. 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 its energy assets and liabilities, which includes generation assets, gas transportation and storage assets, load
obligations and bilateral physical and financial transactions, based on historical and forward values for factors such as customer
demand, weather, commodity availability and commodity prices. The Company's VaR model is based on a one-day holding
period at a 95% confidence interval for the forward 36 months, not including the spot month. The VaR model is not a complete
picture of all risks that may affect the Company's results. Certain events such as counterparty defaults, regulatory changes, and
extreme weather and prices that deviate significantly from historically observed values are not reflected in the model.
The following table summarizes average, maximum and minimum VaR for NRG's commodity portfolio, calculated using
the VaR model for the years ended December 31, 2021 and 2020:
(In millions)
VaR as of December 31, (a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
For the year ended December 31,
Average(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Maximum(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Minimum(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021
2020
30 $
35 $
53
23
30
30
47
22
(a) Calculation includes entire NRG portfolio as of December 31, 2021
(b) Calculation is based on NRG generation assets and load obligations excluding the acquisition of Direct Energy assets and load obligations in the first
quarter of 2021
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 $242
million as of December 31, 2021, primarily driven by asset-backed transactions. The increase in the VaR for derivative
financial instruments was primarily due to the acquisition of Direct Energy.
73
Retail Customer Credit Risk
NRG is exposed to retail credit risk related to its Business and Home customers. 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. 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, 2021, the Company's retail customer credit exposure to Home and Business customers was
diversified across many customers and various industries, as well as government entities. The Company's provision for credit
losses resulting from credit risk was $698 million, $108 million and $95 million for the years ending December 31, 2021, 2020
and 2019, respectively. As a result of Winter Storm Uri, the Company incurred additional credit losses from Business
customers primarily due to a segment of customers whose contracts included a pass through of wholesale power prices which
were significantly escalated during the storm and from customers who failed to meet their obligations in ERCOT load
curtailment programs.
Liquidity Risk
Liquidity risk arises from the general funding needs of the Company's activities and 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 as of December 31, 2021, a $0.50
per MMBtu decrease in natural gas prices across the term of the marginable contracts would cause an increase in margin
collateral posted of approximately $828 million and a 1.00 MMBtu/MWh decrease in heat rates for heat rate positions would
result in an increase in margin collateral posted of approximately $378 million. This analysis uses simplified assumptions and is
calculated based on portfolio composition and margin-related contract provisions as of December 31, 2021.
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.
As of December 31, 2021, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, and registered
commodity exchanges and certain long-term agreements, was $2.2 billion, of which the Company held collateral (cash and
letters of credit) against those positions of $598 million resulting in a net exposure of $1.6 billion. NRG periodically receives
collateral from counterparties in excess of their exposure. Collateral amounts shown include such excess while net exposure
shown excludes excess collateral received. Approximately 87% of the Company's exposure before collateral is expected to roll
off by the end of 2023. 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, 2021, the aggregate credit 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Exposure (a) (b)
(% of Total)
67 %
33
100 %
74
Category
Investment grade . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-Investment grade/Non-Rated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Exposure (a) (b)
(% of Total)
55 %
45
100 %
(a) Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices
(b) The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long-
term contracts
The Company has no exposure to wholesale counterparties in excess of 10% of the total net exposure discussed above as
of December 31, 2021. Changes in hedge positions and market prices will affect credit exposure and counterparty
concentration.
During Winter Storm Uri, the Company experienced nonperformance by a counterparty in one of its bilateral financial
hedging transactions, resulting in exposure of $403 million. The Company is pursuing all means available to enforce its rights
under this transaction but, given the size of the exposure, cannot determine with certainty what the amount of its ultimate
recovery will be. The full exposure was recorded as a provision for credit losses during the year ended December 31, 2021.
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, NYMEX and Nodal. 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, primarily
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, 2021, aggregate credit risk exposure managed by NRG to these counterparties was approximately $1.1 billion for
the next five years.
Interest Rate Risk
As of December 31, 2021, the Company's debt fair value was $8.3 billion and carrying value was $8.0 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
$690 million.
Credit Risk Related Contingent Features
Certain of the Company's hedging and trading agreements contain provisions that entitle the counterparty to demand that
the Company post additional collateral if the counterparty determines that there has been deterioration in the Company's credit
quality, generally termed “adequate assurance” under the agreements, or require the Company to post additional collateral if
there were a downgrade in the Company's credit rating. In addition, as a result of the acquisition of Direct Energy from
Centrica, certain of the Company’s agreements as of December 31, 2021, were still supported by credit support posted by
Centrica, and as a result could require the Company to post collateral upon a deterioration or downgrade of Centrica. The
collateral potentially required for contracts with adequate assurance clauses that are in a net liability position as of
December 31, 2021, was $1.0 billion. 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 $70 million as of
December 31, 2021. In the event of a downgrade in the Company's credit rating and if called for by the counterparty, $1 million
of additional collateral would be required for all contracts with credit rating contingent features as of December 31, 2021.
75
Currency Exchange Risk
NRG is subject to transactional exchange rate risk from transactions with customers in countries outside of the United
States, primarily within Canada, as well as from intercompany transactions between affiliates. Transactional exchange rate risk
arises from the purchase and sale of goods and services in currencies other than our functional currency or the functional
currency of an applicable subsidiary. NRG hedges a portion of its forecasted currency transactions with foreign exchange
forward contracts. As of December 31, 2021, NRG is exposed to changes in foreign currency primarily associated with the
purchase of U.S. dollar denominated natural gas for its Canadian business and entered into foreign exchange contracts with
notional amount of $279 million.
The Company is subject to translation exchange rate risk related to the translation of the financial statements of its foreign
operations into U.S. dollars. Costs incurred and sales recorded by subsidiaries operating outside of the United States are
translated into U.S. dollars using exchange rates effective during the respective period. As a result, the Company is exposed to
movements in the exchange rates of various currencies against the U.S. dollar, primarily the Canadian and Australian dollars. A
hypothetical 10% appreciation in major currencies relative to the U.S. dollar as of December 31, 2021 would have resulted in
an increase of $10 million to net income within the Consolidated Statement of Operations.
Item 8 — Financial Statements and Supplementary Data
The financial statements and schedules are included 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, 2021.
Changes in Internal Control over Financial Reporting
During the year ended December 31, 2021, the Company completed its acquisition of Direct Energy. In the first quarter of
2022, the Company integrated a significant component of Direct Energy's accounting systems into NRG's legacy ERP system.
As part of this integration, the Company has completed the evaluation of our internal controls related to Direct Energy, and
designed and implemented a control structure over Direct Energy's operations. Other than the Direct Energy acquisition, 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 2021 that materially affected, or are reasonably likely to materially affect,
NRG’s internal control over financial reporting.
76
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, 2021.
On January 5, 2021, NRG acquired Direct Energy, as further described in Note 4, Acquisitions, Discontinued Operations
and Dispositions. Direct Energy comprised of approximately 35% of the Company's total assets as of December 31, 2021 and
approximately 58% of the Company's total revenues for the year ended December 31, 2021. As of December 31, 2021, we are
in the process of evaluating the internal controls of the acquired business and integrated it into our existing operations. The
acquired business has, therefore, been excluded from management's assessment of internal control over financial reporting for
the year ended December 31, 2021.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2021 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.
77
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
NRG Energy, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited NRG Energy, Inc. and subsidiaries' (the Company) internal control over financial reporting as of
December 31, 2021, 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, 2021, 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, 2021 and 2020, the related consolidated
statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year
period ended December 31, 2021, and the related notes and financial statement schedule II (collectively, the consolidated
financial statements), and our report dated February 24, 2022 expressed an unqualified opinion on those consolidated financial
statements.
The Company acquired Direct Energy during 2021 and management excluded from its assessment of the effectiveness of the
Company's internal control over financial reporting as of December 31, 2021. Direct Energy's internal control over financial
reporting are associated with 35% of total assets and 58% of total revenues included in the consolidated financial statements of
the Company as of and for the year ended December 31, 2021. Our audit of internal control over financial reporting of the
Company also excluded an evaluation of the internal control over financial reporting of Direct Energy.
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 24, 2022
/s/ KPMG LLP
78
Item 9B — Other Information
Entry into a Material Definitive Agreement.
On February 22, 2022, the Company entered into a Supplemental Indenture (the “Supplemental Indenture”), by and
among the Company, the guarantors named therein (the “Guarantors") and Delaware Trust Company, as trustee and conversion
agent (the “Trustee”), to supplement the Indenture, dated as of May 24, 2018 (the “Indenture”), among the Company, the
Guarantors and the Trustee, governing the Convertible Senior Notes. Pursuant to the Supplemental Indenture, the Company has
irrevocably (i) eliminated the right of the Company to elect Physical Settlement (as defined in the Indenture) as the Settlement
Method (as defined in the Indenture) on any conversion of Convertible Senior Notes that occurs on or after the date of the
Supplemental Indenture and (ii) elected that, with respect to any Combination Settlement (as defined in the Indenture), the
Specified Dollar Amount (as defined in the Indenture) per $1,000 principal amount of the Convertible Senior Notes shall be no
lower than $1,000.
The foregoing description of the Supplemental Indenture does not purport to be complete and is qualified in its entirety
by reference to the full text of the Supplemental Indenture, a copy of which is filed as Exhibit 4.52 to this report and is
incorporated herein by reference.
Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory
Arrangements of Certain Officers.
Effective February 24, 2022, Emily C. Picarello, CPA, was named as Principal Accounting Officer of NRG Energy,
Inc. Ms. Picarello, age 41, joined the Company in December 2018 and served as Assistant Controller for the Company through
November 2021, when she was promoted to Vice President and Corporate Controller. Ms. Picarello will continue in this role
reporting to Alberto Fornaro, NRG's Executive Vice President and Chief Financial Officer.
Prior to her employment with the Company, Ms. Picarello spent over seven years with PVH Corp., one of the largest
global apparel companies in the world, first as the Director of Financial Reporting and then as the Vice President, Financial
Reporting. Prior to Ms. Picarello's time with PVH Corp., she was an auditor with KPMG LLP for over eight years, holding
various positions including Audit Senior Manager.
Item 9C— Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
79
Item 10 — Directors, Executive Officers and Corporate Governance
Directors and Executive Officers
PART III
Information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy
Statement for its 2022 Annual Meeting of Stockholders.
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 Code of
Conduct" is available in print to any stockholder who requests it.
Other information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive
Proxy Statement for its 2022 Annual Meeting of Stockholders.
Item 11 — Executive Compensation
Information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy
Statement for its 2022 Annual Meeting of Stockholders.
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Securities Authorized for Issuance under Equity Compensation Plans
Plan Category
Equity compensation plans approved by security
holders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity compensation plans not approved by security
holders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,534,959
$
(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)
2,514,828 (1) $
20,131 (2)
—
20.07
20.07
11,508,073
— (4)
11,508,073 (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, 2021, there were
2,636,199 shares reserved from the Company's treasury shares for the ESPP
(2) Consists of shares issuable under the NRG GenOn LTIP. The plans is listed as “not approved” because it was not subject to separate line item approval by
NRG's stockholders when the Merger was approved. See Item 15 — Note 21, Stock-Based Compensation, to Consolidated Financial Statements for a
discussion of the NRG GenOn LTIP
(3) Consists of 8,871,874 shares of common stock under NRG's LTIP and 2,636,199 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. For further discussion, see Note 21, Stock-Based Compensation
NRG LTIP currently provides for grants of restricted stock units, relative 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. The
purpose of the NRG 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.
Other information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive
Proxy Statement for its 2022 Annual Meeting of Stockholders.
80
Item 13 — Certain Relationships and Related Transactions, and Director Independence
Information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy
Statement for its 2022 Annual Meeting of Stockholders.
Item 14 — Principal Accounting Fees and Services
Information required by this Item is incorporated by reference to the similarly named section of NRG's Definitive Proxy
Statement for its 2022 Annual Meeting of Stockholders.
81
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, Philadelphia, PA, Auditor Firm ID: 185, are included herein:
Consolidated Statements of Operations — Years ended December 31, 2021, 2020, and 2019
Consolidated Statements of Comprehensive Income — Years ended December 31, 2021, 2020, and 2019
Consolidated Balance Sheets — As of December 31, 2021 and 2020
Consolidated Statements of Cash Flows — Years ended December 31, 2021, 2020, and 2019
Consolidated Statements of Stockholders' Equity — Years ended December 31, 2021, 2020, and 2019
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
82
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
NRG Energy, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of NRG Energy, Inc. and subsidiaries (the Company) as of
December 31, 2021 and 2020, the related consolidated statements of operations, comprehensive income, stockholders' equity,
and cash flows for each of the years in the three-year period ended December 31, 2021, 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, 2021 and 2020, and the results
of its operations and its cash flows for each of the years in the three-year period ended December 31, 2021, 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, 2021, 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 24, 2022 expressed an unqualified opinion on the effectiveness of the Company's
internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the
PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and
the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement,
whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the
consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such
procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by management,
as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a
reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial
statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or
disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or
complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated
financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate
opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Evaluation of the sufficiency of audit evidence over operating revenues
As discussed in Note 3 to the consolidated financial statements, the Company had $26.989 billion of operating
revenues. Operating revenue is derived from various revenue streams in different geographic markets and the
Company’s processes and related information technology (IT) systems used to record revenue differ for each of these
revenue streams.
We identified the evaluation of the sufficiency of audit evidence over operating revenues as a critical audit matter
which required a high degree of auditor judgment due to the number of revenue streams and IT systems involved in the
revenue recognition process. This included determining the revenue streams over which procedures were to be
performed and evaluating the nature and extent of evidence obtained over the individual revenue streams as well as
operating revenue in the aggregate. It also included the involvement of IT professionals with specialized skills and
knowledge to assist in the performance of certain procedures.
83
The following are the primary procedures we performed to address this critical audit matter. We, with the assistance of
IT professionals, applied auditor judgment to determine the revenue streams over which procedures were performed as
well as the nature and extent of such procedures. For certain revenue streams, we evaluated the design and tested the
operating effectiveness of certain internal controls over the Company’s revenue recognition processes. For certain
revenue streams, we involved IT professionals, who assisted in testing certain IT applications used by the Company in
its revenue recognition processes. In addition, we assessed recorded revenue for a selection of transactions by
comparing the amounts recognized to underlying documentation, including contracts with customers. In addition, we
evaluated the sufficiency of audit evidence obtained over operating revenues by assessing the results of procedures
performed, including the appropriateness of such evidence.
Fair value of customer relationship intangible assets
As discussed in Note 4 to the consolidated financial statements, the Company acquired Direct Energy on January 5,
2021 for consideration of $3.724 billion. The Company recorded the identifiable assets acquired and liabilities
assumed at fair value at the acquisition date, including $1.277 billion of customer relationship intangible assets which
represent the generation of future income reflective of Direct Energy's customer base. Customer relationship intangible
assets were valued using the excess earnings method of the income approach.
We identified the evaluation of the fair value of customer relationship intangible assets acquired in the Direct Energy
transaction as a critical audit matter. A higher degree of auditor judgment was required to evaluate the customer
attrition used in the excess earnings method. Changes in the customer attrition could have a significant impact on the
forecasted future cash flows used in the excess earnings method and the resulting fair value of the customer
relationship intangible assets.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design
and tested the operating effectiveness of certain internal controls related to the Company's acquisition-date valuation
process, including controls over the development of the customer attrition. We performed sensitivity analyses over the
Company's customer attrition used to determine the estimated fair value of the customer relationship intangible assets
to assess the effect of changes in that assumption on the Company's determination of fair value. We evaluated the
customer attrition by comparing it to the Company's actual customer attrition.
/s/ KPMG LLP
We have served as the Company's auditor since 2004.
Philadelphia, Pennsylvania
February 24, 2022
84
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Year Ended December 31,
2021
2020
2019
(In millions, except per share amounts)
Operating Revenues
Total operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 26,989 $
9,093 $
9,821
Operating Costs and Expenses
Cost of operations (excluding depreciation and amortization shown below) . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selling, general and administrative costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provision for credit losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition-related transaction and integration costs . . . . . . . . . . . . . . . . . . . . . . . . .
Total operating costs and expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment losses on investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on debt extinguishment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total other expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from Continuing Operations Before Income Taxes . . . . . . . . . . . . . . . . . . . . . . .
Income tax expense/(benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from Continuing Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from discontinued operations, net of income tax . . . . . . . . . . . . . . . . . . . . . . . . .
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
20,482
785
544
1,293
698
93
23,895
247
3,341
17
—
63
(77)
(485)
(482)
2,859
672
2,187
—
2,187
6,540
435
75
810
108
23
7,991
3
1,105
17
(18)
67
(9)
(401)
(344)
761
251
510
—
510
Less: Net income attributable to redeemable noncontrolling interest . . . . . . . . . . . . .
Net Income Attributable to NRG Energy, Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Income Per Share Attributable to NRG Energy, Inc. Common Stockholders
—
2,187 $
—
510 $
7,303
373
5
760
95
2
8,538
7
1,290
2
(108)
66
(51)
(413)
(504)
786
(3,334)
4,120
321
4,441
3
4,438
Weighted average number of common shares outstanding — basic . . . . . . . . . . . . . . . . . .
245
245
262
Income from continuing operations per weighted average common share — basic . . . . . . $
8.93 $
2.08 $
15.71
Income from discontinued operations per weighted average common share — basic . . . . . $
Net Income per Weighted Average Common Share — Basic . . . . . . . . . . . . . . . . . . $
Weighted average number of common shares outstanding — diluted . . . . . . . . . . . . . . . .
Income from continuing operations per weighted average common share — diluted . . . . . $
Income from discontinued operations per weighted average common share — diluted . . . $
— $
8.93 $
245
8.93 $
— $
— $
2.08 $
246
2.07 $
— $
1.23
16.94
264
15.59
1.22
Net Income per Weighted Average Common Share — Diluted . . . . . . . . . . . . . . . . . $
8.93 $
2.07 $
16.81
See notes to Consolidated Financial Statements
85
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
For the Year Ended December 31,
2021
2020
2019
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2,187 $
510 $
4,441
Other Comprehensive Income/(Loss), net of tax
Foreign currency translation adjustments, net of income tax . . . . . . . . . . . . . . . . . .
(5)
Available-for-sale securities, net of income tax . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Defined benefit plans, net of income tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other comprehensive income/(loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Comprehensive Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Net income attributable to redeemable noncontrolling interest . . . . . . . . . . . .
—
85
80
2,267
—
8
—
(22)
(14)
496
—
(1)
(19)
(78)
(98)
4,343
3
Comprehensive Income Attributable to NRG Energy, Inc. . . . . . . . . . . . . . . . . . . . . $
2,267 $
496 $
4,340
See notes to Consolidated Financial Statements
86
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions)
Current Assets
ASSETS
As of December 31,
2021
2020
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Funds deposited by counterparties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Uplift securitization proceeds receivable from ERCOT . . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
250 $
845
15
3,245
689
498
Derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash collateral paid in support of energy risk management activities . . . . . . . . . . . . . . . .
Prepayments and other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Assets
Equity investments in affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating lease right-of-use assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangible assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear decommissioning trust fund . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4,613
291
395
10,841
1,688
157
271
1,795
2,511
1,008
2,527
2,155
3,905
19
6
904
—
327
560
50
257
6,028
2,547
346
301
579
668
890
261
3,066
Other non-current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
229
10,653
23,182 $
216
6,327
14,902
See notes to Consolidated Financial Statements
87
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (Continued)
(In millions, except share data)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
As of December 31,
2021
2020
Current portion of long-term debt and finance leases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Current portion of operating lease liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash collateral received in support of energy risk management activities . . . . . . . . . . . . .
Accrued expenses and other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4 $
81
2,274
3,387
845
1,324
7,915
Other Liabilities
Long-term debt and finance leases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-current operating lease liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear decommissioning reserve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear decommissioning trust liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other non-current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commitments and Contingencies
Stockholders' Equity
Common stock; $0.01 par value; 500,000,000 shares authorized; 423,547,174 and
423,057,848 shares issued; and 243,753,899 and 244,231,933 shares outstanding at
December 31, 2021 and 2020, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retained earnings/(accumulated deficit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Treasury stock, at cost; 179,793,275 and 178,825,915 shares at December 31, 2021
and 2020, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated other comprehensive loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Stockholders' Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Liabilities and Stockholders' Equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
See notes to Consolidated Financial Statements
7,966
236
321
666
1,412
73
993
11,667
19,582
4
8,531
464
(5,273)
(126)
3,600
23,182 $
1
69
649
499
19
678
1,915
8,691
278
303
565
385
19
1,066
11,307
13,222
4
8,517
(1,403)
(5,232)
(206)
1,680
14,902
88
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
For the Year Ended December 31,
2021
2020
2019
Cash Flows from Operating Activities
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Income from discontinued operations, net of income tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjustments to reconcile net income to net cash provided by operating activities:
Distributions from and equity in earnings of unconsolidated affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion of asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provision for credit losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of nuclear fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of financing costs and debt discounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on debt extinguishment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of in-the-money contracts and emission allowances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of unearned equity compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net gain on sale of assets and disposal of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Oil lower of cost or market adjustment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Uplift securitization proceeds receivable from ERCOT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash (used)/provided 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
2,187 $
510 $
4,441
—
2,187
20
785
30
698
51
39
77
106
21
(261)
544
(3,626)
604
797
40
—
(689)
(1,232)
(61)
31
476
(55)
(89)
493
—
—
510
45
435
45
108
54
48
9
70
22
(23)
93
137
228
127
51
29
—
—
27
4
(56)
(42)
(84)
1,837
—
321
4,120
14
373
51
95
52
26
51
72
20
(23)
113
34
(3,353)
105
37
—
—
5
22
29
(177)
(75)
(186)
1,405
8
493 $
1,837 $
1,413
Payments for acquisitions of assets, businesses and leases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net (purchases)/sales of emissions 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 contributions to discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash (used)/provided by continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash used by discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Cash (Used)/Provided by Investing Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(3,559) $
(284) $
(269)
—
(751)
710
830
—
—
—
(3,039)
—
(230)
(10)
(492)
439
81
2
—
—
(494)
—
(3,039) $
(494) $
(355)
(228)
11
(416)
381
1,294
(91)
(44)
6
558
(2)
556
89
(In millions)
Cash Flows from Financing Activities
For the Year Ended December 31,
2021
2020
2019
Proceeds from issuance of long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1,100 $
3,234 $
1,833
Payments for short and long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(1,861)
Payments of dividends to common stockholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net receipts/(payments) from settlement of acquired derivatives that include financing elements . . . . . . . . . . . .
Payments for share repurchase activity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Payments for debt extinguishment costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Payments of debt issuance costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net (repayments)/proceeds of Revolving Credit Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from issuance of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchase of and distributions to noncontrolling interests from subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash (used)/provided by continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash provided by discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Cash (Used)/Provided by Financing Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(319)
938
(48)
(65)
(18)
—
1
—
(272)
—
(335)
(295)
(7)
(229)
(5)
(75)
(83)
1
(2)
(2,571)
(32)
(4)
(1,440)
(26)
(35)
83
3
(2)
2,204
—
(2,191)
43
(272) $
2,204 $
(2,148)
Effect of exchange rate changes on cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in Cash from discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(2)
—
(2)
—
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 .
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period . . . . . . $
(2,820)
3,930
3,545
385
1,110 $
3,930 $
—
49
(228)
613
385
For further discussion of supplemental cash flow information see Note 26, Cash Flow Information
See notes to Consolidated Financial Statements
90
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In millions)
Common
Stock
Additional
Paid-In
Capital
Retained
Earnings/
(Accumulated
Deficit)
Treasury
Stock
Accumulated
Other
Comprehensive
Loss
Total
Stock-
holders'
Equity
Balances at December 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . $
4 $
8,510 $
(6,022) $ (3,632) $
(94) $
(1,234)
Net income attributable to NRG Energy, Inc. . . . . . . . . . . . . . . . .
4,438
Other comprehensive loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Shares reissuance for ESPP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Share repurchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity-based awards activity, net(a)
. . . . . . . . . . . . . . . . . . . . . . . .
Issuance of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Common stock dividends and dividend equivalents declared(b)
. .
(98)
2
(1,409)
1
(16)
6
(32)
4,438
(98)
3
(1,409)
(16)
6
(32)
Balance at December 31, 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
4 $
8,501 $
(1,616) $ (5,039) $
(192) $
1,658
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
510
Other comprehensive loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repurchase of partners' equity interest in VIE . . . . . . . . . . . . . . .
Shares reissuance for ESPP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Share repurchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity-based awards activity, net(a)
. . . . . . . . . . . . . . . . . . . . . . . .
Issuance of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Common stock dividends and dividend equivalents declared(b)
. .
18
(3)
1
4
(197)
(297)
(14)
510
(14)
18
4
(197)
(3)
1
(297)
Balance at December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
4 $
8,517 $
(1,403) $ (5,232) $
(206) $
1,680
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,187
Other comprehensive income . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Shares reissuance for ESPP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Share repurchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity-based awards activity, net(a)
. . . . . . . . . . . . . . . . . . . . . . . .
Issuance of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Common stock dividends and dividend equivalents declared(b)
. .
80
3
(44)
1
12
1
(320)
2,187
80
4
(44)
12
1
(320)
Balance at December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
4 $
8,531 $
464 $ (5,273) $
(126) $
3,600
(a) Includes $(9) million, $(27) million and $(36) million of equivalent shares purchased in lieu of tax withholding on equity compensation issuances for the
years ended December 31, 2021, 2020 and 2019, respectively
(b) Dividends per common share were $1.30, $1.20 and $0.12 for each of the years ended December 31,2021, 2020 and 2019, respectively
See notes to Consolidated Financial Statements
91
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 a consumer services company built on dynamic retail brands. NRG brings
the power of energy to customers by producing and selling energy and related products and services, nation-wide in the U.S.
and Canada in a manner that delivers value to all of NRG's stakeholders. NRG sells power, natural gas, home and power
services, and develops innovative, sustainable solutions, predominately under the brand names NRG, Reliant, Direct Energy,
Green Mountain Energy, Stream, and XOOM Energy. The Company has a customer base that includes approximately 6 million
Home customers as well as commercial, industrial, and wholesale customers, supported by approximately 18,000 MW of
generation.
On January 5, 2021, the Company acquired Direct Energy, which had been a North American subsidiary of Centrica.
Direct Energy is a leading retail provider of electricity, natural gas, and home and business energy related products and services
in North America, with operations in all 50 U.S. states and 8 Canadian provinces. The acquisition increases NRG's retail
portfolio by over 3 million customers and complements its integrated model. It also broadens the Company's presence in the
Northeast and into states and locales where it does not currently operate, supporting NRG's objective to diversify its business.
See Note 4, Acquisitions, Discontinued Operations and Dispositions, to the Consolidated Financial Statements for further
discussion of the acquisition of Direct Energy.
On December 1, 2021, the Company sold approximately 4,850 MWs of fossil generating assets from its East and West
regions to Generation Bridge, an affiliate of ArcLight Capital Partners. NRG received $623 million of net proceeds, after
purchase price adjustments pursuant to the terms of the Purchase and Sale Agreement entered into on February 28, 2021. As
part of the transaction, NRG entered into a tolling agreement for the 866 MW Arthur Kill plant in New York City through April
2025.
During the second quarter of 2021, the results of the PJM Base Residual Auction for the 2022/2023 delivery year were
released, leading the Company to announce the near-term retirement of approximately 1,600 MW of its PJM coal generating
assets in June 2022. On July 30, 2021, PJM identified reliability impacts resulting from the proposed deactivation of one of
those assets, Indian River Unit 4. On August 27, 2021 the Company notified PJM that it would continue operations at Indian
River Unit 4 until the reliability upgrades identified by PJM were completed, provided that the unit receives a satisfactory and
compensatory reliability must run arrangement. See Item 15 — Note 11, Asset Impairments, to the Consolidated Financial
Statements for further discussion. The Company is continuing to evaluate the viability of the remaining PJM generating assets.
The Company manages its operations based on the combined results of the retail and wholesale generation businesses
with a geographical focus.
The Company's business is segmented as follows:
• Texas, which includes all activity related to customer, plant and market operations in Texas;
• East, which includes all activity related to customer, plant and market operations in the East;
• West/Services/Other, which includes the following assets and activities: (i) all activity related to plant and market
operations in the West and Canada, (ii) the Services businesses (iii) activity related to the Cottonwood facility, (iv) the
remaining renewables activity, including the Company’s equity method investment in Ivanpah Master Holdings, LLC,
and (v) activity related to the Company’s equity method investment for the Gladstone power plant in Australia; and
• Corporate activities.
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 U.S. GAAP. The ASC,
established by the FASB, is the source of authoritative U.S. 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
92
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.
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. Though some amounts are segregated into separate accounts, not all funds are contractually restricted. Based
on the Company's intention, these funds are not available for the payment of general corporate obligations; however, they are
available for liquidity management. 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.
Winter Storm Uri Uplift Securitization Proceeds
The Texas Legislature passed HB 4492 for ERCOT to mitigate exceptionally high price adders and ancillary service costs
incurred by LSEs during Winter Storm Uri. HB 4492 authorized ERCOT to obtain $2.1 billion of financing to distribute to
LSEs that were charged and paid to ERCOT those highly priced ancillary service and ORDPA during Winter Storm Uri.
In December 2021, ERCOT filed with the PUCT a calculation of each LSE’s share of proceeds based on the settlement
methodology. The Company accounted for the proceeds we will receive by analogy to the contribution model within ASC
958-605, Not-for-Profit Entities- Revenue Recognition and the grant model within IAS 20, Accounting for Government Grants
and Disclosure of Government Assistance, as a reduction to expenses in the consolidated statements of operations in the annual
period for which the proceeds are intended to compensate. The Company expects to receive proceeds of $689 million from
ERCOT in the second quarter of 2022 and we concluded that the threshold for recognizing a receivable was met in December
2021 as the amounts to be received are determinable and ERCOT was directed by its governing body, the PUCT, to take all
actions required to effectuate the $2.1 billion funding approved in the DOO. The associated expense reduction is reflected in
Cost of operations within our consolidated statements of operations as that is where the initial costs which are being
compensated for were recorded.
Credit Losses
On January 1, 2020, the Company adopted ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326):
Measurement of Credit Losses on Financial Instruments, or ASU No. 2016-13, using the modified retrospective approach.
Following the adoption of the new standard, the Company’s process of estimating expected credit losses remains materially
consistent with its historical practice. Information prior to January 1, 2020, which was previously referred to as the allowance
and provision for bad debt, has not been restated and continues to be reported under the accounting standards in effect for that
period.
Retail trade receivables are reported on the balance sheet net of the allowance for credit losses. The Company accrues an
allowance for current expected credit losses based on (i) estimates of uncollectible revenues by analyzing accounts receivable
aging and current and reasonable forecasts of expected economic factors including, but not limited to, unemployment rates and
weather-related events, (ii) historical collections and delinquencies, and (iii) counterparty credit ratings for commercial and
industrial customers. The Company writes off customer contract receivable balances against the allowance for credit losses
when it is determined a receivable is uncollectible.
The following table represents the activity in the allowance for credit losses for the year ended December 31, 2021:
(In millions)
Beginning balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Acquired balance from Direct Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Provision for credit losses(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Write-offs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Recoveries collected . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ending balance(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(a) Includes bilateral finance hedging risk of $403 million accounted for under ASC 815
Year Ended December 31,
2021
2020
67 $
112
698
(224)
30
683 $
43
—
108
(101)
17
67
93
The increase in the provision for credit losses during the year ended December 31, 2021, compared to 2020 was primarily
due to the impacts of Winter Storm Uri on bilateral finance hedging risk of $403 million, counterparty credit risk of
$126 million and ERCOT default shortfall payments of $67 million.
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.
(In millions)
Year Ended December 31,
2020
2019
2021
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
250 $
3,905 $
Funds deposited by counterparties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
845
15
19
6
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown
in the statements of cash flows . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1,110 $
3,930 $
345
32
8
385
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.
Inventory
Inventory is valued at the lower of weighted average cost or market, and consists principally of natural gas, fuel oil, coal,
spare parts and finished goods. The Company removes natural gas inventory in the delivery of goods to customers and as they
are used in the production of electricity or steam. The Company removes fuel oil and coal inventories as they are used in the
production of electricity. 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 natural gas, fuel oil, coal
and spare parts costs in the ordinary course of business. Inventory is valued at the lower of cost or net realizable value with cost
being determined on a first in first out basis for finished goods and weighted average cost method for all other inventories. 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.
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 11,
Asset Impairments.
94
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, 2021, 2020 and 2019, was $2 million,
$2 million and $3 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, or as an asset if the issuance costs relate to revolving debt agreements or certain other financing arrangements.
Intangible Assets
Intangible assets represent contractual rights held by the Company. The Company recognizes specifically identifiable
intangible assets including emission allowances, customer and supply contracts, customer relationships, marketing partnerships,
trade names 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, 2021 and 2020, the Company had accumulated amortization related to its intangible assets of $1.6 billion and
$1.4 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, Intangibles-Goodwill and Other, or 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 indicating that it is more-likely-than-not that no impairment occurred, 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 12, Goodwill and Other
Intangibles.
Income Taxes
The Company accounts for income taxes using the liability method in accordance with ASC 740, Income Taxes, or
ASC 740, which requires that the Company use the asset and liability method of accounting for deferred income taxes and
provide deferred income taxes for all significant temporary differences.
The Company has two categories of income tax expense or benefit — current and deferred, as follows:
•
•
Current income tax expense or benefit consists solely of current taxes payable less applicable tax credits, and
Deferred income tax expense or benefit is the change in the net deferred income tax asset or liability, excluding
amounts charged or credited to accumulated other comprehensive income
95
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 expected to be in effect when the deferred tax is realized.
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 is the amount of benefit that has
surpassed the more-likely-than-not threshold, as it 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 740 and as discussed further in Note 20, Income Taxes, changes to existing net deferred tax
assets or valuation allowances or changes to uncertain tax benefits, are recorded to income tax (benefit)/expense.
Contract and Emission Credit Amortization
Assets and liabilities recognized through acquisitions related to the purchase and sale of energy and energy-related
products in future periods for which the fair value has been determined to be significantly less or more than market are
amortized to operating revenues or cost of operations over the term of each underlying contract based on actual generation and/
or contracted volumes.
Emission credits represent the right to generate a specified amount of emissions, including sulfur dioxide, nitrogen oxides
and carbon dioxide, over a compliance period. Emission credits held for use are amortized to cost of operations based on the
weighted average cost of the allowances held.
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 842, 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.
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 842.
Gross Receipts and Sales Taxes
In connection with its retail sales, 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, 2021, 2020 and 2019, the
Company's revenues and cost of operations included gross receipts taxes of $184 million, $107 million and $109 million,
respectively. Additionally, the Company records sales taxes collected from its taxable retail 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 Operations
Cost of operations includes cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging
activities, contract and emission credit amortization, operations and maintenance, and other cost of operations.
Cost of Fuel, Purchased Energy and Other Cost of Sales
Cost of fuel is primarily the costs associated with procurement, transportation and storage of natural gas, oil and coal to
operate the generation portfolio, which is expensed as the fuel is consumed. Purchased energy primarily relates to purchases to
supply the Company's customer base, which includes spot market purchases, as well as contracts of various quantities and
durations, including renewable purchased power agreements under PPAs with third-party developers, which are accounted for
as NPNS (see further discussion in Derivative Financial Instruments below). Other cost of sales primarily consists of TDSP
expenses.
The cost of fuel is based on actual and estimated fuel usage for the applicable reporting period. The cost to deliver energy
and related services to customers is based on actual and estimated supply volumes for the applicable reporting period. A portion
of the cost of energy, $189 million, $98 million and $103 million as of December 31, 2021, 2020 and 2019, respectively, was
accrued and consisted of estimated transmission and distribution charges not yet billed by the transmission and distribution
utilities.
96
In estimating supply volumes, the Company considers the effects of historical customer volumes, weather factors and
usage by customer class. Transmission and distribution delivery fees are estimated using the same method used for electricity
sales and services to retail customers. In addition, ISO fees are estimated based on historical trends, estimated supply volumes
and initial ERCOT ISO settlements. Volume estimates are then multiplied by the supply rate and recorded as cost of operations
in the applicable reporting period.
Derivative Instruments
The Company accounts for derivative instruments under ASC 815, which requires the Company to record all derivatives
on the balance sheet at fair value and changes in fair value in earnings, unless they qualify for the NPNS exception. The
Company's primary derivative instruments are power and natural gas purchase or sales contracts, fuels purchase contracts and
other energy related commodities used to mitigate variability in earnings due to fluctuation in market prices. In addition, in
order to mitigate foreign exchange risk associated with the purchase of USD denominated natural gas for the Company's
Canadian business, NRG enters into foreign exchange contract agreements.
As of December 31, 2021 and 2020 the Company did not have derivative instruments that were designated as cash flow or
fair value or hedge.
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 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 instruments are recognized in
earnings.
Mark-to-Market for Economic Hedging Activities
NRG enters into derivative instruments to manage price and delivery risk, optimize physical and contractual assets in the
portfolio and manage working capital requirements. The mark-to-market for economic hedging activities are recognized to cost
of operations during the reporting period.
Operations and Maintenance and Other Cost of Operations
Operations and maintenance costs include major and other routine preventative (planned outage) and corrective (forced
outage) maintenance activities to ensure the safe and reliable operation of the Company's generation portfolio in compliance
with all local, state and federal requirements. Operations and maintenance costs are also costs associated with retaining and
maintaining the Company's customer base, such as call center support, portfolio maintenance and data analytics. Other cost of
operations primarily includes gross receipts taxes, insurance, property taxes and asset retirement obligation expense.
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, 2021, 2020 and 2019, amounts recognized as foreign currency
transaction gains/(losses) were immaterial. The Company's cumulative translation adjustment balances as of December 31,
2021, 2020 and 2019 were $(8) million, $(2) million and $(13) 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 5, Fair Value of Financial Instruments, for a further
discussion of derivative concentrations.
97
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 5, Fair Value of
Financial Instruments, for a further discussion of fair value of financial instruments.
Asset Retirement Obligations
The Company accounts for AROs in accordance with ASC 410-20, Asset Retirement Obligations, or ASC 410-20.
Retirement obligations associated with long-lived assets included within the scope of ASC 410-20 are those for which a legal
obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of
promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. ASC 410-20
requires an entity to recognize the fair value of a liability for an ARO in the period in which it is incurred and a reasonable
estimate of fair value can be made.
Upon initial recognition of a liability for an ARO, the Company capitalizes the asset retirement cost by increasing the
carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its future value, while
the capitalized cost is depreciated over the useful life of the related asset. See Note 14, 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, or ASC 715. 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 performance stock units is estimated on the date of grant using a
Monte Carlo valuation model. NRG uses the Company's common stock price on the date of grant as the fair value of the
Company's deferred stock units. The fair value of the Company's restricted stock units is derived from the closing price of
NRG's common stock at the grant date. 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.
Tax Equity Arrangements
The Company’s redeemable noncontrolling interest in subsidiaries represented third-party interests in the net assets under
certain tax equity arrangements, which were consolidated by the Company, that had been entered into to finance the cost of
solar energy systems under operating leases. The Company determined that the provisions in the contractual agreements of
these structures represented substantive profit sharing arrangements. Further, the Company had determined that the appropriate
methodology for calculating the redeemable noncontrolling interest that reflected the substantive profit sharing arrangements
was a balance sheet approach that utilized the HLBV method. Under the HLBV method, the amounts reported as redeemable
98
noncontrolling interests represented the amounts the investors that were 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. The investors’ interests in the results of
operations of the funding structures were determined as 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 included estimated calculations of taxable income or losses for each reporting
period. During the first quarter of 2020, the Company repurchased its partners' equity interest, which was the Company's last
remaining tax equity arrangement.
Redeemable Noncontrolling Interest
The following table reflects the changes in the Company's redeemable noncontrolling interest balance for the years ended
December 31, 2020 and 2019.
Balance as of December 31, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Distributions to redeemable noncontrolling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income attributable to redeemable noncontrolling interest - continuing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance as of December 31, 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repurchase of redeemable noncontrolling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance as of December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(In millions)
19
(2)
3
20
(20)
—
Sale-Leaseback Arrangements
NRG is party to sale-leaseback arrangements that provide for the sale of certain assets to a third party and simultaneously
leases back the same asset to the Company. If the seller-lessee transfers control of the underlying assets to the buyer-lessor, the
arrangement is accounted for under ASC 842-40, Sale-Leaseback Transactions. These arrangements are classified as operating
leases on the Company's consolidated balance sheets. See Note 10, Leases, for further discussion.
Marketing and Advertising Costs
The Company expenses its marketing and advertising costs as incurred and includes them 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, 2021, 2020 and 2019 were
$109 million, $74 million and $66 million, respectively.
Business Combinations
The Company accounts for its business combinations in accordance with ASC 805, Business Combinations, or ASC 805,
which 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. The Company also recognizes and
measures the goodwill acquired or a gain from a bargain purchase in 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.
99
Reclassifications
Certain prior period amounts have been reclassified for comparative purposes. The reclassifications did not affect results
from operations, net assets or cash flows.
Recent Accounting Developments - Guidance Adopted in 2021
ASU 2019-12 — In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the
Accounting for Income Taxes, or ASU 2019-12, to simplify various aspects related to accounting for income taxes. The
guidance in ASU 2019-12 amends the general principles in Topic 740 to eliminate certain exceptions for recognizing deferred
taxes for investment, performing intraperiod allocation and calculating income taxes in interim periods. This ASU also includes
guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to
members of a consolidated group. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, and interim
periods within those fiscal years. The Company adopted the amendments effective January 1, 2021 using the prospective
approach. The adoption did not have a material impact on the Company's results of operations, statements of cash flows, or
statement of financial position.
ASU 2021-10 — In November 2021, the FASB issued ASU 2021-10, Government Assistance (Topic 832): Disclosures by
Business Entities about Government Assistance, which requires additional disclosures for transactions with a government
accounted for by applying a grant or contribution model by analogy, including: (i) the nature of the transactions and the related
accounting policy used to account for the transactions; (ii) the line items on the balance sheet and income statement that are
affected by the transactions, and the amounts applicable to each financial statement line item; and (iii) significant terms and
conditions of the transactions, including commitments and contingencies. The amendments were applied prospectively to all
transactions within the scope of the amendments. Early application of the new standard is permitted and the effect of the new
standard only impacted the Company’s financial statement disclosures.
Recent Accounting Developments - Guidance Not Yet Adopted
ASU 2020-06 — In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options
(Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40), or ASU 2020-06. The
guidance in ASU 2020-06 reduces the number of accounting models for convertible debt instruments and convertible preferred
stock. In addition, ASU 2020-06 improves and amends the related earnings per share guidance. This standard is effective for
fiscal years beginning after December 15, 2021. The Company adopted this standard on January 1, 2022 using the modified
retrospective approach. As a result of the provisions of the amended guidance, the Company estimates a $100 million decrease
to additional paid-in capital, a $57 million decrease to debt discount, a $57 million increase to retained earnings, and a
$14 million decrease to long-term deferred tax liabilities. The Company does not expect the adoptions of ASU 2020-06 to have
a material impact on its statement of operations, statements of cash flows or earnings per share amounts.
ASU 2021-08 — In October 2021, the FASB issued ASU No. 2021-08, Business Combinations (Topic 805): Accounting
for Contract Assets and Contract Liabilities from Contracts with Customers, or ASU 2021-08. Under current GAAP, an
acquirer generally recognizes assets acquired and liabilities assumed in a business combination, including contract assets and
contract liabilities arising from revenue contracts with customers and other similar contracts that are accounted for in
accordance with ASC 606, Revenue from Contracts with Customers, or ASC 606, at fair value on the acquisition date. ASU
2021-08 requires that an entity recognize and measure contract assets and contract liabilities acquired in a business combination
in accordance with ASC 606. At the acquisition date, an acquirer should account for the related revenue contracts in accordance
with ASC 606 as if it had originated the contracts, which should generally result in an acquirer recognizing and measuring the
acquired contract assets and contract liabilities consistent with how they were recognized and measured in the acquiree’s
financial statements. This update also provides certain practical expedients for acquirers when recognizing and measuring
acquired contract assets and contract liabilities from revenue contracts in a business combination. The amendments in this
update are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years and
should be applied prospectively to business combinations occurring on or after the effective date of the amendments. Early
adoption is permitted, including adoption in an interim period. Adoption during an interim period requires retrospective
application to all business combinations for which the acquisition date occurs on or after the beginning of the fiscal year that
includes the interim period of early application and prospectively to all business combinations that occur on or after the date of
initial application. The Company does not expect the adoption of ASU 2021-08 to have a material impact on the consolidated
financial statements and disclosures.
100
Note 3 — Revenue Recognition
The Company's policies with respect to its various revenue streams are detailed below. The Company generally 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 Revenue
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 and natural gas contracts, the Company’s performance
obligation with the customer is satisfied over time and performance obligations for its electricity and natural gas products are
recognized as the customer takes possession of the product. The Company also allocates the contract consideration to distinct
performance obligations 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,
utilities, 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.
As contracts for retail electricity and natural gas 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 consist of revenues billed to a third party at either market or negotiated contract
terms 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 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 used to hedge the sale of electricity
are recorded net within operating revenues in the consolidated statements of operations in accordance with ASC 815.
Ancillary revenues, included in Other revenue, are recognized over time as the obligation is fulfilled, using the output
method for measuring progress of satisfaction of performance obligations.
Capacity Revenue
The Company's largest sources of capacity revenues are capacity auctions in PJM, ISO-NE and NYISO. Capacity
revenues also include revenues billed to a third party at either market or negotiated contract terms 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 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.
Performance Obligations
As of December 31, 2021, estimated future fixed fee performance obligations are $258 million, $48 million and
$1 million for fiscal years 2022, 2023 and 2024, respectively. These performance obligations are for cleared auction MWs in
the PJM, ISO-NE, NYISO and MISO capacity auctions and are subject to penalties for non-performance.
101
Disaggregated Revenue
The following tables represent the Company’s disaggregation of revenue from contracts with customers for the years
ended December 31, 2021, 2020 and 2019:
(In millions)
Retail revenue
Home(a)
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Total retail revenue . . . . . . . . . . . . . . . . . . . . . . . . . .
Energy revenue(c) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capacity revenue(c)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mark-to-market for economic hedging activities(d) . . . . . .
Contract amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenue(b)(c)
Total operating revenue . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Lease revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Realized and unrealized ASC 815 revenue . . . . . . . .
Less: Contract amortization . . . . . . . . . . . . . . . . . . . . . . . .
For the Year Ended December 31, 2021
Texas
East
West/Services/
Other
Corporate/
Eliminations
Total
5,665 $
1,959 $
2,053 $
(1) $
2,745
8,410
329
—
(3)
—
1,557
10,293
—
130
—
9,903
11,862
508
718
(88)
(26)
59
1,237
3,290
371
57
(86)
(4)
25
13,033
3,653
1
184
(26)
7
(96)
(4)
—
(1)
7
—
13
—
(9)
10
—
16
—
9,676
13,885
23,561
1,215
775
(164)
(30)
1,632
26,989
8
234
(30)
Total revenue from contracts with customers . . . . . . . . $
10,163 $
12,874 $
3,746 $
(6) $
26,777
(a) Home includes Services
(b) Other Revenue in Texas includes ancillary revenues of $1.3 billion driven by high pricing during Winter Storm Uri
(c) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815:
(In millions)
Texas
East
West/Services/
Other
Corporate/
Eliminations
Total
Energy revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
— $
131 $
2 $
3 $
Capacity revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
133
149
(8)
—
(12)
—
—
136
149
113
(d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815
102
(In millions)
Retail revenue
Home(a)
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Total retail revenue . . . . . . . . . . . . . . . . . . . . . . . . . .
Energy revenue(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capacity revenue(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mark-to-market for economic hedging activities(c) . . . . . .
Other revenue(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total operating revenue . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Lease revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Realized and unrealized ASC 815 revenue . . . . . . . .
For the Year Ended December 31, 2020
Texas
East
West/Services/
Other
Corporate/
Eliminations
Total
5,027 $
1,210 $
96 $
(2) $
1,034
6,061
24
—
2
222
6,309
—
30
95
1,305
183
620
88
62
2,258
1
314
—
96
333
61
(3)
43
530
17
38
—
(2)
(1)
(1)
8
(8)
(4)
—
3
6,331
1,129
7,460
539
680
95
319
9,093
18
385
Total revenue from contracts with customers . . . . . . . . $
6,279 $
1,943 $
475 $
(7) $
8,690
(a) Home includes Services
(b) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815:
(In millions)
Texas
East
West/Services/
Other
Corporate/
Eliminations
Total
Energy revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
— $
67 $
43 $
(5) $
Capacity revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
28
156
3
—
(2)
—
—
105
156
29
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815
(In millions)
Retail revenue
Home(a)
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Total retail revenue . . . . . . . . . . . . . . . . . . . . . . . . . .
Energy revenue(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capacity revenue(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mark-to-market for economic hedging activities(c) . . . . . .
Other revenue(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total operating revenue . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Lease revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Realized and unrealized ASC 815 revenue . . . . . . . .
For the Year Ended December 31, 2019
Texas
East
West/Services/
Other
Corporate/
Eliminations
Total
5,027 $
1,173 $
57 $
(3) $
1,205
6,232
529
—
47
261
7,069
—
1,562
74
1,247
322
664
(29)
58
2,262
1
183
—
57
318
36
16
70
497
19
67
—
(3)
—
—
(1)
(3)
(7)
—
(2)
6,254
1,279
7,533
1,169
700
33
386
9,821
20
1,810
7,991
Total revenue from contracts with customers . . . . . . . . $
5,507 $
2,078 $
411 $
(5) $
(a) Home includes Services
(b) The following amounts of energy, capacity and other revenue relate to derivative instruments and are accounted for under ASC 815:
(In millions)
Texas
East
West/Services/
Other
Corporate/
Eliminations
Total
Energy revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1,459 $
98 $
39 $
(1) $
1,595
Capacity revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
56
109
5
—
12
—
—
109
73
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815
103
Contract Balances
The following table reflects the contract assets and liabilities included in the Company's balance sheet as of December 31,
2021 and 2020:
(In millions)
December 31, 2021
December 31, 2020
Deferred customer acquisition costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
133 $
Accounts receivable, net - Contracts with customers . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable, net - Derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable, net - Affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,057
182
6
Total accounts receivable, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
3,245 $
Unbilled revenues (included within Accounts receivable, net - Contracts with
customers) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred revenues (a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
1,574 $
227 $
113
866
33
5
904
393
60
(a) Deferred revenues from contracts with customers for the years ended December 31, 2021 and 2020 were approximately $224 million and $31 million,
respectively
The revenue recognized from contracts with customers during the years ended December 31, 2021 and 2020 relating to
the deferred revenue balance at the beginning of each period was $23 million and $13 million, respectively. The change in
deferred revenue balances during the years ended December 31, 2021 and 2020 was primarily due to the timing difference of
when consideration was received and when the performance obligation was transferred.
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.
Note 4 —Acquisitions, Discontinued Operations and Dispositions
Acquisitions
Direct Energy Acquisition
On January 5, 2021 (the "Acquisition Closing Date"), the Company acquired all of the issued and outstanding common
shares of Direct Energy, which had been a North American subsidiary of Centrica plc. Direct Energy is a leading retail provider
of electricity, natural gas, and home and business energy related products and services in North America, with operations in all
50 U.S. states and 8 Canadian provinces. The acquisition increased NRG's retail portfolio by over 3 million customers and
strengthens its integrated model. It also broadens the Company's presence in the Northeast and into states and locales where it
did not previously operate, supporting NRG's objective to diversify its business.
The Company paid an aggregate purchase price of $3.625 billion in cash, subject to a purchase price adjustment of
$77 million. The Company funded the purchase price using a combination of $715 million of cash on hand, $166 million from a
draw on its Revolving Credit Facility (of which $107 million was used to fund acquisition costs and financing fees that are not
included in the aggregate purchase price above) as well as approximately $2.9 billion in secured and unsecured corporate debt
issued in December 2020. The final purchase price adjustment resulted in additional payment of $22 million, which was paid in
December 2021.
104
The Company also increased its collective collateral facilities by $3.4 billion as of the Acquisition Closing Date to meet
the additional liquidity requirements related to the acquisition, as detailed in the following table:
Available on Acquisition Closing Date
Revolving Credit Facility commitment increase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Revolving Credit Facility new tranche . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Facility agreement in connection with the sale of pre-capitalized trust securities . . . . . . . . . . . . . . . . .
Available as of December 31, 2020
Credit default swap facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Revolving accounts receivable financing facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repurchase facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Bilateral letter of credit facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(In millions)
802
273
874
150
750
75
475
Total Increases to Liquidity and Collateral Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
3,399
For further discussion see Note 13, Long-term Debt and Finance Leases.
Acquisition costs of $25 million and $17 million for the years ended December 31, 2021 and 2020, respectively, are
included in acquisition-related transaction and integration costs in the Company's consolidated statement of operations.
The acquisition has been recorded as a business combination under ASC 805 with identifiable assets acquired and
liabilities assumed recorded at their estimated fair values on the acquisition date. The purchase price is allocated as follows:
(In millions)
Current Assets
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Funds deposited by counterparties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash collateral paid in support of energy risk management activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepayments and other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Assets
Goodwill(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangible assets, net: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Customer relationships(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Customer and supply contracts(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Trade names(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Renewable energy credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total intangible assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other non-current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
152
21
9
1,802
106
1,014
233
173
3,510
151
1,250
1,277
610
310
124
2,321
531
31
4,133
7,794
105
Current Liabilities
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash collateral received in support of energy risk management activities . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued expenses and other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other Liabilities
Derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other non-current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(In millions)
1,116
1,266
21
670
3,073
562
320
115
997
Total Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
4,070
Direct Energy Purchase Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
3,724
(a) Goodwill arising from the acquisition is attributed to the value of the platform acquired and the synergies expected from combining the operations of Direct
Energy with NRG's existing businesses. Goodwill was allocated to the Texas, East, and West/Services/Other segments of $427 million, $648 million , and
$175 million, respectively. Goodwill expected to be deductible for tax purposes is $322 million
(b) The weighted average amortization period for total amortizable intangible assets is 12 years
Measurement Period Adjustments
The following measurement period adjustments were recognized during the quarter ended December 31, 2021:
(In millions)
Assets
Prepayments and other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total decrease in assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Liabilities
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Accrued expenses and other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total decrease in liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Net measurement period adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(10)
(7)
(17)
(4)
(20)
(18)
(42)
25
The measurement period adjustments are attributable primarily to refinement of the underlying assumptions used to
estimate the fair value of assets acquired and liabilities assumed as more information was obtained about facts and
circumstances that existed as of the Acquisition Closing Date.
Fair Value Measurement of Intangible Assets
The fair values of intangible assets as of the Acquisition Closing Date were measured primarily based on significant
inputs that are observable and unobservable in the market and thus represent Level 2 and Level 3 measurements, respectively.
Significant inputs were as follows:
Customer relationships — Customer relationships, reflective of Direct Energy’s customer base, were valued using an
excess earning method of the income approach. Under this approach, the Company estimated the present value of expected
future cash flows resulting from existing customer relationships, considering attrition and charges for contributory assets (such
as net working capital, fixed assets, workforce and trade names) utilized in the business, discounted at an independent power
producer peer group’s weighted average cost of capital. The customer relationships are amortized to depreciation and
amortization, ratably based on discounted future cash flows. The weighted average amortization period is 12 years.
106
Customer and supply contracts — The fair value of in-market and out-of-market customer and supply contracts were
estimated based on contractual terms compared to market prices as of the Acquisition Closing Date. The majority of the
contracts were valued using prices provided by external sources, primarily price quotations available through broker or over-
the-counter and online exchanges. For contracts for which external sources or observable market quotes were not available,
these values were based on valuation techniques including, but not limited to, internal models based on fundamental analysis of
the market and extrapolation of the observable market data with similar characteristics. In addition, the Company applied a
credit reserve to reflect credit risk, which is calculated based on published default probabilities. The customer and supply
contracts are amortized to revenue and cost of operations, respectively, based upon the fair market value, as of the acquisition
date, for each delivery month. The weighted average amortization period is 14 years.
Trade names — Trade names were valued using a "relief from royalty" method of the income approach. Under this
approach, the fair value is estimated to be the present value of royalties saved because NRG owns the intangible asset and
therefore does not have to pay a royalty for its use. The trade names are amortized to depreciation and amortization, on a
straight line basis, over a weighted average amortization period of 15 years.
Renewable energy credits — Renewable energy credits were valued based on the market prices as of the Acquisition
Closing Date. Renewable energy credits are retired, as required, for the applicable compliance period. They are expensed to
cost of operations based on customer usage.
Fair Value Measurement of Derivative Assets and Liabilities
The fair values of derivatives assets and liabilities as of the Acquisition Closing Date were as follows:
(In millions)
Fair Value
Total
Level 1
Level 2
Level 3
Derivatives assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,545 $
155 $
1,272 $
Derivatives liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,828
207
1,489
118
132
Refer to Note 5, Fair Value of Financial Instruments for discussion on derivative fair value measurements.
Supplemental Information
For the Year Ended December 31, 2021 Direct Energy contributed revenue and income before income taxes of $15.6
billion and $2.4 billion, respectively.
Supplemental Unaudited Pro Forma Financial Information
The following table provides unaudited pro forma combined financial information of NRG and Direct Energy, after giving
effect to the Direct Energy acquisition and related financing transactions as if they had occurred on January 1, 2019. The pro
forma financial information has been prepared for illustrative and informational purposes only, and is not intended to project
future operating results or indicative of what our financial performance would have been had the transactions occurred on the
date assumed. No effect has been given to operating synergies.
(In millions)
For the Year Ended December 31,
2021
2020
2019
Total operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
26,987 $
21,326 $
Income from continuing operations . . . . . . . . . . . . . . . . . . . .
2,225
471
23,673
3,623
Amounts above reflect certain pro forma adjustments that were directly attributable to the Direct Energy acquisition.
These adjustments include the following:
(i) Income statement effects of fair value adjustments based on the purchase price allocation including amortization of
intangible assets, depreciation of property, plant and equipment and lease expense.
(ii) Interest expense assumes the financing transactions directly attributable to the Direct Energy acquisition occurred on
January 1, 2019.
(iii) Removal of Direct Energy historical interest expense associated with related party notes receivable/payable between Direct
Energy and Centrica and its subsidiaries, as those notes are assumed to be repaid as of January 1, 2019.
(iv) Elimination of transactions between NRG and Direct Energy.
(v) Adjustments to reflect all acquisition costs occurring during the year ended December 31, 2019.
107
(vi) Tax effects of pro forma adjustments on all periods presented and shifting the recognition of one time tax benefits resulting
from the acquisition from the year ended December 31, 2021 to the year ended December 31, 2019.
Midwest Generation Lease Purchase — On September 29, 2020, Midwest Generation acquired all of the ownership
interests in the Powerton facility and Units 7 and 8 of the Joliet facility, which were being leased through 2034 and 2030,
respectively, for approximately $260 million. The purchase was funded with cash-on-hand. Upon closing, lease expense related
to these facilities, which totaled approximately $14 million in 2019, and the operating lease liability of $148 million were
eliminated.
Stream Energy Acquisition — On August 1, 2019, the Company completed the acquisition of Stream Energy's retail
electricity and natural gas business operating in 9 states and Washington, D.C. for $329 million, including working capital and
other adjustments of approximately $29 million. The acquisition increased NRG's retail portfolio by approximately 600,000
RCEs or 450,000 customers.
The purchase price was allocated as follows:
Account receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other net current and non-current working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Marketing partnership . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Customer relationships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Trade name . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other intangible assets
Goodwill (a)
Stream Purchase Price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(In millions)
98
(73)
5
154
85
28
26
6
329
(a) Goodwill arising from the acquisition is attributed to the value of the platform acquired and the synergies expected from combining the operations of
Stream Energy with NRG's existing businesses. Goodwill of $5 million and $1 million was assigned to the Texas and East segments, respectively, and is
not deductible for tax purposes
Dispositions
Sale of 4,850 MW of Fossil generating assets
On December 1, 2021, the Company closed the previously announced sale of approximately 4,850 MWs of fossil
generating assets from its East and West regions to Generation Bridge, an affiliate of ArcLight Capital Partners. Proceeds of
$760 million were reduced by working capital and other adjustments of $137 million, resulting in net proceeds of $623 million.
The Company recorded a gain of $210 million from the sale, which includes the $39 million indemnification liability recorded
as discussed below. As part of the transaction, NRG entered into a tolling agreement for the 866 MW Arthur Kill plant in New
York City through April 2025.
As part of the agreement to sell the fossil generating assets, NRG has agreed to indemnify Generation Bridge for certain
future environmental compliance costs up to $39 million. The indemnity term will expire on December 1, 2028. The Company
has recorded the liability within accrued expenses and other current liabilities and other non-current liabilities.
Sale of Agua Caliente
On February 3, 2021, the Company closed on the sale of its 35% ownership in the Agua Caliente solar project to
Clearway Energy, Inc. for $202 million. NRG recognized a gain on the sale of $17 million, including cash disposed of
$7 million.
Sale of Home Solar
In the third quarter of 2020, the Company concluded its Home Solar business was held for sale and recorded an
impairment loss of $29 million, as further discussed in Note 11, Asset Impairments. On November 13, 2020, the Company
completed the sale of the Home Solar business for cash proceeds of $66 million, resulting in a $2 million loss on the sale. In
connection with the sale, the Company extinguished debt of $27 million and recognized a $5 million loss on the
extinguishment.
Company completed other asset sales for cash proceeds of $12 million and $15 million during the years ended December
31, 2021 and 2020, respectively.
108
Discontinued Operations
Sale of South Central Portfolio
On February 4, 2019, the Company completed the sale of its South Central Portfolio to Cleco for cash consideration of $1
billion excluding working capital and other adjustments. The Company concluded that the divested business met the criteria for
discontinued operations, as the disposition represented a strategic shift in the business in which NRG operates. In connection
with the transaction, NRG also entered into a transition services agreement to provide certain corporate services to the divested
business, which have been substantially completed in 2020.
The South Central Portfolio includes the 1,177 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 did not use held-for-sale or discontinued
operations treatment in accounting for the Cottonwood facility.
Summarized results of South Central discontinued operations for the year ended December 31, 2019 were as follows:
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Operating costs and expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain from operations of discontinued components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on disposal of discontinued operations, net of tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain from discontinued operations, including disposal, net of tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(In millions)
31
(23)
8
20
28
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. In
connection with the transaction, NRG entered into a transition services agreement to provide certain corporate services to the
divested businesses in 2018, which concluded in 2020. During the year ended December 31, 2019, the Company recorded an
adjustment to reduce the purchase price by $15 million in connection with the completion of the Patriot Wind project. During
the year ended December 31, 2019, the Company reduced the liability related to the indemnification of NRG Yield for any
increase in property taxes for certain solar properties by $22 million due to updated estimates.
Carlsbad
On February 6, 2018, NRG entered into an agreement with NRG Yield and GIP to sell 100% of its membership interests
in Carlsbad Energy Holdings LLC, which owns the Carlsbad project, for $385 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. At the time of the sale of NRG Yield and the Renewables Platform in August 2018, the Company
concluded that the Carlsbad project met the criteria for discontinued operations and accordingly, all current and prior period
results for Carlsbad were reclassified as discontinued operations. The transaction closed on February 27, 2019. Carlsbad will
continue to have a ground lease and easement agreement with NRG with an initial term ending in 2039 and two ten-year
extensions. As a result of the transaction, additional commitments related to the project totaled $23 million as of December 31,
2021 and December 31, 2020.
Summarized results of NRG Yield, Inc. and Renewables Platform and Carlsbad discontinued operations for the year
ended December 31, 2019 were as follows:
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Operating costs and expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain/(loss) from discontinued operations, net of tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain/(loss) on disposal of discontinued operations, net of tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income/(expense) from California property tax indemnification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income/(expense) from other commitments, indemnification and fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income/(loss) on disposal of discontinued operations, net of tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income/(loss) from discontinued operations, net of tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
19
(9)
(5)
5
265
22
4
291
296
(In millions)
109
GenOn
On June 14, 2017, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the
Texas 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 Texas Bankruptcy Court; and accordingly, NRG deconsolidated GenOn and its subsidiaries for
financial reporting purposes as of such date. For the Year Ended December 31, 2019 NRG recorded $3 million loss from
discontinued operations, net of tax for GenOn results of operations.
Note 5 — Fair Value of Financial Instruments
For cash and cash equivalents, funds deposited by counterparties, restricted cash, accounts and other receivables, accounts
payable, restricted cash, and cash collateral paid 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 value and fair value of the Company's long-term debt, including current portion, is as follows:
As of December 31,
2021
2020
(In millions)
Carrying Amount
Fair Value
Carrying Amount
Fair Value
Long-term debt, including current portion (a)
. . . . . . . . . $
8,040 $
8,327 $
8,781
$
9,446
(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.
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.
110
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:
(In millions)
Investments in securities (classified within other current and non-current
Total
Level 1
Level 2
Level 3
As of December 31, 2021
Fair Value
assets) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
32 $
15 $
17 $
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 (classified within other non-current assets):
U.S. government and federal agency obligations . . . . . . . . . . . . . . . . . . .
Derivative assets:
33
112
100
44
122
494
4
1
Foreign exchange contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodity contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
7,139
Measured using net asset value practical expedient:
Equity securities-nuclear trust fund investments . . . . . . . . . . . . . . . . . . .
Equity securities (classified within other non-current assets) . . . . . . . . . .
99
7
33
111
—
—
—
494
—
1
—
981
—
—
—
—
—
—
—
—
—
—
1
100
44
122
—
4
—
1
5,701
—
457
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 8,188 $ 1,635 $ 5,990 $
457
Derivative liabilities:
Foreign exchange contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1 $
— $
1 $
Commodity contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,798 $
626 $ 4,008 $
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,799 $
626 $ 4,009 $
—
164
164
111
(In millions)
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 (classified within other non-current assets):
U.S. government and federal agency obligations . . . . . . . . . . . . . . . . . . .
Derivative assets:
23
70
89
36
144
434
7
1
Commodity contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
821
Measured using net asset value practical expedient:
Equity securities-nuclear trust fund investments . . . . . . . . . . . . . . . . . . .
Equity securities (classified within other non-current assets) . . . . . . . . . .
87
8
As of December 31, 2020
Fair Value
Total
Level 1
Level 2
Level 3
25 $
10 $
15 $
—
—
—
—
—
—
—
—
—
—
1
89
36
144
—
6
—
23
69
—
—
—
434
1
1
59
623
139
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,745 $
597 $
914 $
139
Derivative liabilities:
Commodity contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
884 $
884 $
86 $
86 $
643 $
643 $
155
155
The following tables reconcile, for the years ended December 31, 2021 and 2020, 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:
(In millions)
Beginning balance as of January 1, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Contracts added from Direct Energy acquisition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total gains realized/unrealized included in earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers into Level 3 (b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers out of Level 3 (b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ending balance as of December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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, 2021 . . . . . . . . . . . . . . . . . . . . . . . .
For the Year Ended December 31, 2021
Fair Value Measurement Using
Significant Unobservable Inputs (Level 3)
Derivatives (a)
$
$
$
(16)
(15)
145
93
71
15
293
120
(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
112
(In millions)
For the Year Ended December 31, 2020
Fair Value Measurement Using
Significant Unobservable Inputs (Level 3)
Derivatives (a)
Beginning balance as of January 1, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
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, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
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, 2020 . . . . . . . . . . . . . . . . . . . . . . . .
$
38
(44)
(13)
1
2
(16)
9
(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 were 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 measured using net asset value practical expedient. See also Note 7, 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 6% of derivative assets and 3% 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 foreign exchange
contracts and interest rate swaps is calculated utilizing the bilateral method based on published default probabilities. For
commodities, to the extent that NRG's net exposure under a specific master agreement is an asset, the Company uses the
counterparty's default swap rate. If the exposure under a specific master agreement is a liability, the Company uses NRG's
default swap rate. For foreign exchange contracts, interest rate swaps and commodities, the credit reserve is added to the
113
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, 2021 the credit reserve resulted in a
$11 million decrease primarily within cost of operations. As of December 31, 2020 the credit reserve resulted in $2 million
increase primarily within cost of operations.
The fair values in each category reflect the level of forward prices and volatility factors as of December 31, 2021, 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 natural gas and power executed in illiquid
markets as well as financial transmission rights, or FTRs. The significant unobservable inputs used in developing fair value
include illiquid natural gas and 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, 2021 and 2020:
Significant Unobservable Inputs
December 31, 2021
(In millions)
Assets
Liabilities
Valuation
Technique
Significant
Unobservable
Input
Low
High
Weighted
Average
Fair Value
Input/Range
Natural Gas Contracts . $
16 $
Discounted Cash
Flow
1
Forward Market
Price (per MMBtu)
$
3 $
40 $
Power Contracts . . . . .
392
FTRs . . . . . . . . . . . . . .
49
$
457 $
121
42
164
Discounted Cash
Flow
Forward Market
Price (per MWh)
Discounted Cash
Flow
Auction Prices (per
MWh)
3
(122)
212
43
15
35
0
Significant Unobservable Inputs
December 31, 2020
Fair Value
Input/Range
(In millions)
Assets
Liabilities
Power Contracts . . . . . $
111 $
FTRs . . . . . . . . . . . . . .
28
$
139 $
143
12
155
Valuation
Technique
Significant
Unobservable
Input
Discounted Cash
Flow
Discounted Cash
Flow
Forward Market
Price (per MWh)
Auction Prices (per
MWh)
Low
High
Weighted
Average
$
10 $
105 $
(28)
43
21
0
114
The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable
inputs as of December 31, 2021 and 2020:
Significant Unobservable Input
Forward Market Price Natural Gas/ Power . . . . . . . .
Forward Market Price Natural Gas/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, 2021, the Company recorded $291 million of cash collateral
posted and $845 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, 2021, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, and registered
commodity exchanges and certain long-term agreements, was $2.2 billion and NRG held collateral (cash and letters of credit)
against those positions of $598 million, resulting in a net exposure of $1.6 billion. NRG periodically receives collateral from
counterparties in excess of their exposure. Collateral amounts shown include such excess while net exposure shown excludes
excess collateral received. Approximately 87% of the Company's exposure before collateral is expected to roll off by the end of
2023. 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
Investment grade . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-Investment grade/Non-Rated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net Exposure (a) (b)
(% of Total)
67 %
33
100 %
Net Exposure (a) (b)
(% of Total)
55 %
45
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 wholesale counterparties in excess of 10% of the total net exposure discussed
above as of December 31, 2021. Changes in hedge positions and market prices will affect credit exposure and counterparty
concentration.
115
During Winter Storm Uri, the Company experienced nonperformance by a counterparty in one of its bilateral financial
hedging transactions, resulting in exposure of $403 million. The Company is pursuing all means available to enforce its rights
under this transaction but, given the size of the exposure, cannot determine with certainty what the amount of its ultimate
recovery will be. The full exposure was recorded as a provision for credit losses during the year ended December 31, 2021.
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, NYMEX and Nodal. 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, primarily
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, 2021, aggregate credit risk exposure managed by NRG to these counterparties was approximately $1.1 billion for
the next five years.
Retail Customer Credit Risk
The Company is exposed to retail credit risk through the Company's retail electricity and gas providers, which serve
Home and Business customers. 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, 2021, the Company's retail customer credit exposure to Home and Business 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 provision for credit losses was $698 million, $108 million, and
$95 million for the years ending December 31, 2021, 2020, and 2019, respectively. As a result of Winter Storm Uri, the
Company incurred additional credit losses from Business customers primarily due to a segment of customers whose contracts
included a pass through of wholesale power prices which were significantly escalated during the storm and from customers who
failed to meet their obligations in ERCOT load curtailment programs.
Note 6 — 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,
foreign exchange contracts, and interest rate swaps.
As the Company engages principally in the trading and marketing of its generation assets and retail operations, 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.
116
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 and gas sales from
NRG's retail operations, 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 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 and gas 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.
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, 2021, 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 2036;
Forward and financial contracts for the purchase of fuel commodities relating to the forecasted usage of NRG's
generation assets through 2024;
Other energy derivatives instruments extending through 2029.
Also, as of December 31, 2021, 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 2036;
Load-following forward natural gas sale contracts extending through 2032;
Power tolling contracts through 2038;
Coal purchase contracts through 2023;
Power transmission contracts through 2025;
Natural gas transportation contracts through 2034;
Natural gas storage agreements through 2025; and
Coal transportation contracts through 2029.
Interest Rate Swaps
During the fourth quarter of 2020, NRG entered into $1.6 billion of interest rate hedges associated with anticipated certain
financing needs. As of December 31, 2020, the interest rate hedges were settled in connection with the issuance of fixed rate
debt, resulting in a gain of $11 million that was recorded as a reduction to interest expense.
Foreign Exchange Contracts
In order to mitigate foreign exchange risk primarily associated with the purchase of USD denominated natural gas for the
Company's Canadian business, NRG enters into foreign exchange contract agreements through 2025.
117
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, 2021 and 2020. 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.
(In millions)
Commodity
Emissions
Units
Short Ton . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Renewables Energy Certificates
Certificates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coal
Natural Gas
Oil
Power
Capacity
Short Ton . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MMBtu . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Barrels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MWh . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MW/Day . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign Exchange
Dollars . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
The increase in positions is primarily the result of Direct Energy acquisition.
Fair Value of Derivative Instruments
Total Volume
December 31, 2021 December 31, 2020
1
13
19
813
1
185
—
279
1
5
2
(286)
—
57
(1)
—
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:
Fair Value
Derivative Assets
Derivative Liabilities
December 31,
2021
December 31,
2020
December 31,
2021
December 31,
2020
Foreign exchange contracts - current . . . . . . . . . . . . . . . . $
— $
— $
1 $
Foreign exchange contracts - long-term . . . . . . . . . . . . . .
Commodity contracts- current . . . . . . . . . . . . . . . . . . . . .
Commodity contracts- long-term . . . . . . . . . . . . . . . . . . .
1
4,613
2,526
—
560
261
—
3,386
1,412
Total Derivatives Not Designated as Cash Flow or Fair Value
Hedges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
7,140 $
821 $
4,799 $
—
—
499
385
884
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:
(In millions)
As of December 31, 2021
Foreign exchange contracts:
Derivative assets . . . . . . . . . . . . . . . $
Derivative liabilities . . . . . . . . . . . . .
Total foreign exchange contracts . . . $
Commodity contracts:
Derivative assets . . . . . . . . . . . . . . . . . . . $
Derivative liabilities . . . . . . . . . . . . . . . .
Total commodity contracts . . . . . . . . . . . . $
Total derivative instruments . . . . . . . . . . . $
Gross Amounts Not Offset in the Statement of Financial Position
Gross Amounts of
Recognized Assets/
Liabilities
Derivative
Instruments
Cash Collateral
(Held)/Posted
Net Amount
(1) $
1
— $
(4,440) $
4,440
— $
— $
— $
—
— $
(831) $
17
(814) $
(814) $
—
—
—
1,868
(341)
1,527
1,527
1 $
(1)
— $
7,139 $
(4,798)
2,341 $
2,341 $
118
Gross Amounts Not Offset in the Statement of Financial Position
Gross Amounts of
Recognized Assets/
Liabilities
Derivative
Instruments
Cash Collateral
(Held)/Posted
Net Amount
(In millions)
As of December 31, 2020
Commodity contracts:
Derivative assets . . . . . . . . . . . . . . . . . . . $
Derivative liabilities . . . . . . . . . . . . . . . .
Total commodity contracts . . . . . . . . . . . . $
821 $
(884)
(63) $
(658) $
658
— $
(5) $
—
(5) $
158
(226)
(68)
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 results of operations.
The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges
or fair value hedges and trading activity on the Company's statement of operations. The effect of foreign exchange and
commodity hedges is included within operating revenues and cost of operations and the effect of interest rate hedges is included
in interest expense.
(In millions)
Unrealized mark-to-market results
Year Ended December 31,
2020
2019
2021
Reversal of previously recognized unrealized (gains) on settled positions related
to economic hedges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(41) $
(55) $
Reversal of acquired loss positions related to economic hedges . . . . . . . . . . . . . . .
Net unrealized gains/(losses) on open positions related to economic hedges . . . . .
Total unrealized mark-to-market gains/(losses) for economic hedging activities . .
Reversal of previously recognized unrealized (gains) on settled positions related
to trading activity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reversal of acquired (gain) positions related to trading activity . . . . . . . . . . . . . . .
Net unrealized (losses)/gains on open positions related to trading activity . . . . . . .
Total unrealized mark-to-market (losses)/gains for trading activity . . . . . . . . . . . . .
256
2,501
2,716
(18)
(1)
(13)
(32)
4
(68)
(119)
(20)
—
15
(5)
Total unrealized gains/(losses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2,684 $
(124) $
(In millions)
Year Ended December 31,
2020
2019
2021
Unrealized (losses)/gains included in operating - commodities . . . . . . . . . . . . . . . . . $
(196) $
Unrealized gains/(losses) included in cost of operations- commodities . . . . . . . . . . .
2,880
Total impact to statement of operations- commodities . . . . . . . . . . . . . . . . . . . . . . $
2,684 $
Total impact to statement of operations — interest rate contracts . . . . . . . . . . . . $
— $
90 $
(214)
(124) $
— $
(68)
6
42
(20)
(11)
—
31
20
—
53
(53)
—
(38)
The reversals of acquired loss/(gain) positions were valued based upon the forward prices on the acquisition date. 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.
The gain from open economic hedge positions of $2.5 billion for the year ended December 31, 2021 was primarily the
result of an increase in value of forward positions as a result of increases in natural gas and power prices.
The loss from open economic hedge positions of $68 million for the year ended December 31, 2020 was primarily the
result of a decrease in the value of forward positions as a result of decreases in ERCOT power prices and heat rate contraction,
partially offset by an increase in value of forward positions as a result of decreases in New York capacity prices.
The gain from open economic hedge positions of $42 million for the year ended December 31, 2019 was primarily the
result of an increase in the value of forward purchases of ERCOT heat rate contracts due to ERCOT heat rate expansion.
119
Credit Risk Related Contingent Features
Certain of the Company's hedging and trading agreements contain provisions that entitle the counterparty to demand that
the Company post additional collateral if the counterparty determines that there has been deterioration in the Company's credit
quality, generally termed “adequate assurance” under the agreements, or require the Company to post additional collateral if
there were a downgrade in the Company's credit rating. In addition, as a result of the acquisition of Direct Energy from
Centrica, certain of the Company’s agreements as of December 31, 2021, were still supported by credit support posted by
Centrica, and as a result could require the Company to post collateral upon a deterioration or downgrade of Centrica. The
collateral potentially required for contracts with adequate assurance clauses that are in net liability positions as of December 31,
2021 was $1.0 billion. 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 $70 million as of December 31, 2021. In the
event of a downgrade in the Company's credit rating and if called for by the counterparty, $1 million of additional collateral
would be required for all contracts with credit rating contingent features as of December 31, 2021.
See Note 5, Fair Value of Financial Instruments, for discussion regarding concentration of credit risk.
Note 7 — 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, 2021
As of December 31, 2020
(In millions, except otherwise noted)
Fair
Value
Unrealized
Gains
Unrealized
Losses
Cash and cash equivalents . . . . . . . . . . . $
33 $
— $
U.S. government and federal agency
obligations . . . . . . . . . . . . . . . . . . . . .
Federal agency mortgage-backed
securities . . . . . . . . . . . . . . . . . . . . . . .
Commercial mortgage-backed securities
Corporate debt securities . . . . . . . . . . . .
Equity securities . . . . . . . . . . . . . . . . . . .
112
100
44
122
593
Foreign government fixed income
securities . . . . . . . . . . . . . . . . . . . . . . .
4
5
2
1
7
456
—
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,008 $
471 $
—
1
—
—
1
—
—
2
Weighted-
average
maturities
(in years)
Fair
Value
Unrealized
Gains
Unrealized
Losses
Weighted-
average
maturities
(in years)
— $
23 $
— $
10
25
27
14
—
13
70
89
36
144
521
7
6
4
2
13
372
1
$ 890 $
398 $
—
—
—
—
—
—
—
—
—
10
24
27
12
—
10
120
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.
(In millions)
Year Ended December 31,
2020
2019
2021
Realized gains . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
47 $
34 $
Realized (losses) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from sale of securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(9)
710
(13)
439
Note 8 — Inventory
Inventory consisted of:
(In millions)
As of December 31,
2021
2020
Fuel oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
8 $
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Spare parts and finished goods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
83
206
201
Total Inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
498 $
18
(9)
381
37
73
22
195
327
The Company recorded a $29 million lower of weighted average cost or market adjustment related to fuel oil during the
year ended December 31, 2020.
Note 9 — Property, Plant and Equipment
The Company's major classes of property, plant, and equipment were as follows:
(In millions)
As of December 31,
2021
2020
Depreciable
Lives
Facilities and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1,742 $
3,365
1-40 years
Land and improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nuclear fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hardware and office equipment and furnishings . . . . . . . . . . . . . . . . . . . . . . . . .
Construction in progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total property, plant, and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
271
222
637
124
2,996
(1,308)
Net property, plant, and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1,688 $
329
239
453
97
4,483
(1,936)
2,547
5 years
2-10 years
The Company recorded long-lived asset impairments during the years ended December 31, 2021 and 2020, as further
described in Note 11, Asset Impairments. Depreciation expense of property, plant and equipment recorded during the years
ended December 31, 2021, 2020 and 2019 was $384 million, $295 million and $271 million, respectively.
Note 10 — Leases
The Company leases generating facilities, land, office and equipment, railcars, fleet vehicles and storefront space at retail
stores. Operating leases with an initial term greater than twelve months are recognized as right-of-use assets and lease liabilities
in the consolidated balance sheets. The Company made an accounting policy election, as permitted by ASC 842, for all asset
classes not to recognize right-of-use assets and lease liabilities in the consolidated balance sheets for its short-term leases, which
are leases that have a lease term of twelve months or less. For the initial measurement of lease liabilities, the discount rate that
the Company uses is either the rate implicit in the lease, if known, or its incremental borrowing rate, which is the rate of interest
that the Company would have to pay to borrow, on a collateralized basis, over a similar term an amount equal to the payments
for the lease. The Company recognizes lease expense for all operating leases on a straight-line basis over the lease term. In the
future, should another systematic basis become more representative of the pattern in which the lessee expects to consume the
remaining economic benefit of the right-of-use asset, the Company will use that basis for lease expense.
The Company considers a contract to be or to contain a lease when both of the following conditions apply: 1) an asset is
either explicitly or implicitly identified in the contract and 2) the contract conveys to the Company the right to control the use of
the identified asset for a period of time. The Company has the right to control the use of the identified asset when the Company
121
has both the right to obtain substantially all the economic benefits from the use of the identified asset and the right to direct how
and for what purpose the identified asset is used throughout the period of use.
Lease payments are typically fixed and payable on a monthly, quarterly, semi-annual or annual basis. Lease payments
under certain agreements may escalate over the lease term either by a fixed percentage or a fixed dollar amount. Certain leases
may provide for variable lease payments in the form of payments based on usage, a percentage of sales from the location under
lease, or index-based (e.g., the U.S. Consumer Price Index) adjustments to lease payments. The Company has no leases which
contain residual value guarantees provided by the Company as a lessee.
As described in Note 4, Acquisitions, Discontinued Operations and Dispositions, upon the close of the South Central
Portfolio sale in 2019, the Company entered into an agreement to leaseback the Cottonwood facility through May 2025. The
lease was accounted for in accordance with ASC 842-40, Sale and Leaseback Transactions, as an operating lease and
accordingly, a right-of-use asset and lease liability were established on the lease commencement date and will be amortized
through the end of the lease.
Lease Cost:
(In millions)
For the Year Ended December 31,
2021
2020
2019
Finance lease cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
4 $
3 $
Operating lease cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Short-term lease cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Variable lease cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sublease income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total lease cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
91
3
9
(2)
105 $
100
3
6
(17)
95 $
Other information:
(In millions)
Cash paid for amounts included in the measurement of
lease liabilities:
Operating cash flows from operating leases . . . . . . . . $
Financing cash flows from finance leases . . . . . . . . . .
Right-of-use assets obtained in exchange for new finance
lease liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Right-of-use assets obtained in exchange for new
operating lease liabilities . . . . . . . . . . . . . . . . . . . . . . . . . .
Lease Term and Discount Rate for leases:
For the Year Ended December 31,
2021
2020
2019
102 $
6
16
47
101 $
1
5
4
—
109
3
6
(17)
101
104
—
—
215
Finance leases:
Weighted average remaining lease term (in years) . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average discount rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating leases:
Weighted average remaining lease term (in years) . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average discount rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2021
December 31, 2020
3.6
2.46 %
4.7
5.44 %
1.1
4.79 %
5.3
5.63 %
122
As of December 31, 2021, annual payments based on the maturities of NRG's operating leases are expected to be as
follows:
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total undiscounted lease payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Less: present value adjustment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total discounted lease payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
In millions
96
89
76
52
11
48
372
(55)
317
Note 11 — Asset Impairments
2021 Impairment Losses
During the fourth quarter of 2021, the Company completed its annual budget and analyzed the corresponding impact on
estimated cash flows associated with its long-lived assets. The fair value of the assets was determined using an income
approach by applying a discounted cash flow methodology to the long-term budget for the facility. The income approach
utilized estimates of after-tax cash flows, which were Level 3 fair value measurements, and included key inputs such as
forecasted power prices, fuel costs, operating and maintenance costs, plant investment capital expenditures and discount rates.
Joliet —The Company recognized an impairment loss of $213 million in the East segment as a result of changes in the
long-term outlook of the Joliet facility prompted by market conditions and an assessment of various alternatives for the long-
term operational landscape of the facility including the impact of the CEJA in Illinois, which concluded with the annual budget
process.
Other Impairments — The Company additionally recorded impairment losses of $16 million and $9 million related to
various power plants in the East and West/Service/Other segments, respectively.
The Company also recorded the following impairment in 2021 based on a specific triggering event that occurred using the
same methodology previously discussed:
PJM Asset Impairments — During the second quarter of 2021, the results of the PJM Base Residual Auction for the
2022/2023 delivery year were released leading the Company to announce the near-term retirement of a significant portion of its
PJM coal generating assets in June 2022. The Company considered the decline in PJM capacity prices and the near-term
retirement dates of certain assets to be a trigger for impairment and performed impairment tests on the PJM generating assets
and the goodwill associated with Midwest Generation. Impairment losses of $271 million and $35 million were recorded in the
East segment on the PJM generating assets and Midwest Generation goodwill, respectively.
2020 Impairment Losses
During the fourth quarter of 2020, 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-lives assets. The Cottonwood facility
had estimated cash flows that were lower than its carrying amount and the assets were considered impaired. The fair value of
the assets was determined using an income approach by applying a discounted cash flow methodology to the long-term budget
for the facility. The income approach utilized estimates of after-tax cash flows, which were Level 3 fair value measurements,
and included key inputs such as forecasted power prices, fuel costs, operating and maintenance costs, plant investment capital
expenditures and discount rates.
The Cottonwood facility is being leased through 2025 and the Company recognized an impairment loss of $32 million in
2020 in the West/Services/Other segment associated with the Company's long-term services agreement and related lease
payments, as the carrying amounts of the assets from the contract were higher than the estimated operating cash flow though the
remaining lease period.
The Company also recorded the following impairments in 2020 based on specific triggering events that occurred:
Home Solar — In the third quarter of 2020, the Company concluded its Home Solar business was held for sale and
recorded an impairment loss of $29 million in the West/Services/Other segment to adjust the carrying amount of the assets and
liabilities to fair market value based on indicative sale prices.
123
Petra Nova Parish Holdings — During the first quarter of 2020, due to the decline in oil prices, NRG determined that the
carrying amount of the Company’s equity method investment exceeded the fair value of the investment and that the decline is
considered to be other-than-temporary. In determining the fair value, the Company utilized an income approach to estimate
future project cash flows. The Company recorded an impairment loss of $18 million in the Texas segment, which included the
anticipated drawdown of the $12 million letter of credit posted in September 2019 to cover certain project debt reserve
requirements.
Other Impairments — For the year ended December 31, 2020, the Company recorded $14 million of impairment losses
related to intangible assets in the Texas segment.
2019 Impairment Losses
Petra Nova Parish Holdings — During the third quarter of 2019, NRG contributed $95 million in cash to Petra Nova and
posted a $12 million letter of credit to cover certain project debt reserve requirements. The cash portion of the contribution was
used by Petra Nova to prepay a significant portion of the project debt. As a result, the previously disclosed guarantee of up to
$124 million related to the project level debt provided by NRG was canceled and the remaining project debt became non-
recourse to NRG. In relation to this contribution, the Company evaluated the project for impairment and determined that the
carrying amount of the Company’s equity method investment exceeded the fair value of the investment and that the decline is
considered to be other-than-temporary. In determining the fair value, the Company utilized an income approach and considered
project specific assumptions for the estimated future project cash flows. 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 $101 million.
Other Impairments — For the year ended December 31, 2019, the Company recorded $12 million of impairment losses
primarily related to investments and intangibles.
Note 12 — Goodwill and Other Intangibles
Goodwill
The table below presents the changes of goodwill for the year ended December 31, 2021 based on the Company's
reportable segments. Goodwill did not change during the year ended December 31, 2020.
(in millions)
Balance as of January 1, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . $
Goodwill resulted from the acquisition of Direct Energy . . . . .
Impairment losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign currency translation . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance as of December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . $
Texas
East
West/Services/
Other
Total
324 $
427
—
—
751 $
240 $
648
(35)
—
853 $
15 $
175
—
1
191 $
579
1,250
(35)
1
1,795
Intangible Assets
The Company's intangible assets as of December 31, 2021, primarily reflect intangible assets established with the
acquisitions of various companies, including Direct Energy, Stream Energy, other retail acquisitions, and Texas Genco.
Intangible assets are comprised of the following:
•
•
•
Emission Allowances — These intangibles primarily consist of SO2 emission allowances, including those established
with the 2006 acquisition of Texas Genco, RGGI emission credits and California carbon allowances. These emission
allowances are held-for-use and are amortized to cost of operations based on units of production.
Customer and supply contracts — These intangibles include the fair value at the acquisition date of in-market and out-
of-market customer and supply contracts from the acquisition of Direct Energy and are amortized to revenue and cost
of operations, respectively, based upon the fair market value, as of the acquisition date, for each delivery month. It also
included energy supply contracts acquired with Stream Energy that represent the fair value at the acquisition date of
in-market contracts for the purchase of energy to serve retail electric customers and are amortized based on the
expected delivery under the respective contracts.
Customer relationships — These intangibles represent the fair value at the acquisition date of acquired businesses'
customer base from the acquisition of Direct Energy and other acquisitions. 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 marketing vendors and loyalty and affinity partners for customer acquisition. 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.
124
•
Other — These intangibles primarily include renewable energy credits. Renewable energy credits are retired, as
required, for the applicable compliance period. They are expensed to cost of operations based on NRG’s customer
usage. It also includes in-market nuclear fuel contracts established from the Texas Genco acquisition in 2006 which
are amortized to cost of operations over expected volumes over the life of each contract, costs to extend the operating
license for STP Units 1 and 2 and intellectual property related to Goal Zero which are amortized to depreciation and
amortization expense.
The following tables summarize the components of NRG's intangible assets:
(In millions)
Year Ended December 31, 2021
January 1, 2021 . . . . . . . . . . . . . . . . . . $
Emission
Allowances
Customer
and Supply
Contracts
Customer
Relationships
Marketing
Partnerships
Trade
Names
Other(b)
Total
672 $
28 $
527 $
285 $
373 $
140 $
2,025
Purchases . . . . . . . . . . . . . . . . . . . . . . .
Acquisition of businesses (a)
. . . . . . . . .
Usage/Sales/Retirements . . . . . . . . . . .
Write-off of fully amortized balances .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2021 . . . . . . . . . . . . . . .
Less accumulated amortization . . . . . .
10
—
(1)
(51)
4
634
(536)
—
610
—
—
—
638
(94)
—
1,308
—
(158)
2
1,679
(518)
—
—
—
—
(1)
284
(123)
—
310
—
—
—
683
(294)
338
124
(364)
(7)
(2)
229
(71)
348
2,352
(365)
(216)
3
4,147
(1,636)
Net carrying amount . . . . . . . . . . . . . . . $
98 $
544 $
1,161 $
161 $
389 $
158 $
2,511
(a) The weighted average life of total acquired amortizable intangibles from the Direct Energy acquisition was 12 years, see Note 4 — Acquisitions,
Discontinued Operations and Dispositions for weighted average life of acquired amortizable intangibles for each intangible asset type
(b) RECs are not subject to amortization and had a carrying value of $123 million
(In millions)
Year Ended December 31, 2020
Emission
Allowances
Customer
and Supply
Contracts
Customer
Relationships
Marketing
Partnerships
Trade
Names
Other(b)
Total
January 1, 2020 . . . . . . . . . . . . . . . . . . $
662 $
28 $
573 $
285 $
373 $
130 $
2,051
Purchases . . . . . . . . . . . . . . . . . . . . . . .
Acquisition of businesses (a)
. . . . . . . . .
Usage/Retirements . . . . . . . . . . . . . . . .
Write-off of fully amortized balances .
Impairment . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . .
December 31, 2020 . . . . . . . . . . . . . . .
Less accumulated amortization . . . . . .
25
—
—
(4)
(14)
3
672
(563)
—
—
—
—
—
—
28
(28)
—
22
—
(70)
—
2
527
(349)
—
—
—
—
—
—
—
—
—
—
—
—
285
(99)
373
(247)
45
—
(35)
—
—
—
140
(71)
70
22
(35)
(74)
(14)
5
2,025
(1,357)
Net carrying amount . . . . . . . . . . . . . . . $
109 $
— $
178 $
186 $
126 $
69 $
668
(a) The weighted average life of acquired intangibles was 5 years for customer relationships
(b) RECs are not subject to amortization and had a carrying value of $28 million
125
The following table presents NRG's amortization of intangible assets for each of the past three years:
(In millions)
Years Ended December 31,
2020
2019
2021
Emission allowances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
24 $
28 $
Customer and supply contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Customer relationships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Marketing partnerships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Trade names . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
66
327
24
47
7
12
74
24
27
3
32
14
44
15
25
4
Total amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
495 $
168 $
134
(a) For the years ended December 31, 2021, 2020 and 2019, other intangibles were amortized to depreciation and amortization expense for $3 million,
$3 million and $4 million, respectively
The following table presents estimated amortization of NRG's intangible assets as of December 31, 2021 for each of the
next five years:
(In millions)
Year Ended December 31,
Emission
Allowances
Customer
and Supply
Contracts
Customer
Relationships
Marketing
Partnerships
Trade
Names
Other
Total
2022 . . . . . . . . . . . . . . . . . . . . . . . . $
14 $
143 $
265 $
23 $
47 $
3 $
2023 . . . . . . . . . . . . . . . . . . . . . . . .
2024 . . . . . . . . . . . . . . . . . . . . . . . .
2025 . . . . . . . . . . . . . . . . . . . . . . . .
2026 . . . . . . . . . . . . . . . . . . . . . . . .
12
12
11
9
120
73
50
52
216
148
110
95
23
23
22
22
46
38
32
24
4
3
4
4
495
421
297
229
206
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, 2021 and 2020, the value of emission allowances held-for-sale was $15 million and $14 million,
respectively, within the Corporate segment. Once transferred to held-for-sale, these emission allowances are prohibited from
moving back to held-for-use.
126
Note 13 — Long-term Debt and Finance Leases
Long-term debt and finance leases consisted of the following:
(In millions, except rates)
Recourse debt:
December 31,
2021
December 31,
2020
Interest rate %
Senior Notes, due 2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
— $
Senior Notes, due 2027 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior Notes, due 2028 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior Notes, due 2029 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior Notes, due 2029 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior Notes, due 2031 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior Notes, due 2032 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Convertible Senior Notes, due 2048(a)
Senior Secured First Lien Notes, due 2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior Secured First Lien Notes, due 2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior Secured First Lien Notes, due 2027 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Senior Secured First Lien Notes, due 2029 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Tax-exempt bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal long-term debt (including current maturities) . . . . . . . . . . . . . . . .
Finance leases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subtotal long-term debt and finance leases (including current maturities) . . . .
Less current maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less debt issuance costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Discounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
375
821
733
500
1,030
1,100
575
600
500
900
500
466
8,100
13
8,113
(4)
(83)
(60)
7.250
6.625
5.750
5.250
3.375
3.625
3.875
2.750
3.750
2.000
2.450
4.450
1.250 - 4.750
1,000
1,230
821
733
500
1,030
—
575
600
500
900
500
466
8,855
4
various
8,859
(1)
(93)
(74)
Total long-term debt and finance leases . . . . . . . . . . . . . . . . . . . . . . . . . $
7,966 $
8,691
(a) The effective interest rate was 5.34% and 5.19% for the years ended December 31, 2021 and 2020, respectively. As of the ex-dividend date of January 31,
2022, the Convertible Senior Notes were convertible at a price of $44.53, which is equivalent to a conversion rate of approximately 22.4563 shares of
common stock per $1,000 principal amount. The remaining period over which the discount on the liability component would have been amortized is 3.7
years. However, the adoption of ASU 2020-06 on January 1, 2022 resulted in the elimination of the debt discount.
Debt includes the following discounts:
(In millions)
Senior Secured First Lien Notes, due 2024, 2025, 2027 and 2029 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Convertible Senior Notes, due 2048 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total discounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
As of December 31,
2021
2020
(2) $
(58)
(60) $
(2)
(72)
(74)
Consolidated Annual Maturities
As of December 31, 2021, annual payments based on the maturities of NRG's debt and finance leases are expected to be
as follows:
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
4
3
603
502
—
7,001
8,113
(In millions)
127
Senior Notes
Issuance of 2032 Senior Notes
On August 23, 2021, the Company issued $1.1 billion of aggregate principal amount of 3.875% senior notes due 2032.
The 2032 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is
paid semi-annually beginning on February 15, 2022 until the maturity date of February 15, 2032. The 2032 Senior Notes were
issued under NRG's Sustainability-Linked Bond Framework, which sets out certain sustainability targets, including reducing
greenhouse gas emissions. Failure to meet such sustainability targets will result in a 25 basis point increase to the interest rate
payable on the 2032 Senior Notes from and including August 15, 2026. The proceeds of the 2032 Senior Notes, along with cash
on hand, were used to fund the redemption of $1.0 billion aggregate principal amount of the 7.250% Senior Notes due 2026 and
$355 million aggregate principal amounts of the 6.625% Senior Notes due 2027.
Issuance of 2029 Senior Unsecured Notes and 2031 Senior Unsecured Notes
On December 2, 2020, NRG issued $500 million aggregate principal amount of 3.375% senior notes due 2029 (the “2029
Unsecured Notes”) and $1.0 billion aggregate principal amount of 3.625% senior notes due 2031 (the “2031 Unsecured Notes”
and, together with the 2029 Unsecured Notes, the “Unsecured Notes”). Interest is payable on the Unsecured Notes on February
15 and August 15 of each year beginning on August 15, 2021 until the maturity date of February 15, 2029 for the 2029
Unsecured Notes and February 15, 2031 for the 2031 Unsecured Notes.
Issuance of 2025 and 2027 Senior Secured First Lien Notes
On December 2, 2020, NRG issued $1.4 billion of aggregate principal amount of senior secured first lien notes, consisting
of $500 million 2.000% senior secured first lien notes due 2025 (the “2025 Secured Notes”) and $900 million 2.450% senior
secured first lien notes due 2027 (the “2027 Secured Notes” and, together with the 2025 Secured Notes, the “2025 and 2027
Senior Secured First Lien Notes”), at a discount. The 2027 Secured Notes were issued under NRG’s Sustainability-Linked
Bond Framework, which sets out certain sustainability targets, including reducing greenhouse gas emissions. Failure to meet
such sustainability targets will result in a 25 basis point increase to the interest rate payable on the 2027 Secured Notes from
and including the interest period ending on June 2, 2026. The 2025 and 2027 Senior Secured First Lien Notes are guaranteed on
a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement.
The 2025 and 2027 Senior Secured First Lien Notes are secured by a first priority security interest in the same collateral that is
pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and
assets owned by NRG and the guarantors. The collateral securing the 2025 and 2027 Senior Secured First Lien Notes will be
released if the Company obtains an investment grade rating from two out of the three rating agencies, subject to an obligation to
reinstate the collateral if such rating agencies withdraw the Company's investment grade rating or downgrade its rating below
investment grade. Interest is payable on the 2025 and 2027 Senior Secured First Lien Notes on June 2 and December 2 of each
year beginning on June 2, 2021 until the maturity date of December 2, 2025 for the 2025 Secured Notes and December 2, 2027
for the 2027 Secured Notes.
Senior Note Redemptions
During the year ended December 31, 2021, the Company redeemed approximately $1.9 billion in aggregate principal
amount of its Senior Notes for $1.9 billion using the proceeds of the 2032 Senior Notes and cash on hand, as detailed in the
table below. In connection with the redemptions, a $77 million loss on debt extinguishment was recorded, which included the
write-off of previously deferred financing costs of $12 million.
(In millions, except percentages)
7.250% Senior Notes, due 2026
6.625% Senior Notes, due 2027
Total
Principal Repurchased
Cash Paid(a)
Average Early Redemption
Percentage
$
$
1,000 $
855
1,855 $
1,056
893
1,949
103.625 %
103.313 %
(a) Includes accrued interest of $29 million for redemptions for the year ended December 31, 2021
2048 Convertible Senior Notes
The Convertible Senior 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.
Prior to February 22, 2022, the Convertible Senior Notes were convertible, under certain circumstances, into the Company's
common stock, cash or a combination thereof (at NRG's option) at a price of $44.89 per common share as of December 31,
2021, which is equivalent to a conversion rate of approximately 22.2761 shares of common stock per $1,000 principal amount
128
of Convertible Senior Notes. On February 22, 2022, the Company irrevocably elected to eliminate the right to settle
conversions only in shares of the Company's common stock, such that any conversion after such date will be settled in cash or a
combination of cash and the Company's common stock. As of December 31, 2020, the Convertible Senior Notes were
convertible at a price of $46.24 per common share, which is equivalent to a conversion rate of approximately 21.6242 shares of
common stock per $1,000 principal amount of Convertible Senior Notes. The carrying amounts of the liability components as
of December 31, 2021 and 2020 of $518 million and $503 million, respectively, were calculated by estimating the fair value of
similar liabilities without a conversion feature at inception and amortizing the debt discount using the effective interest rate over
the life of the note.
Senior Notes Early Redemption
As of December 31, 2021, NRG had the following outstanding issuances of senior notes with an early redemption feature,
or Senior Notes:
i.
ii.
iii.
iv.
v.
vi.
6.625% senior notes, issued August 2, 2016 and due January 15, 2027, or the 2027 Senior Notes;
5.750% senior notes, issued December 7, 2017 and due January 15, 2028, or the 2028 Senior Notes;
5.250% senior notes, issued May 24, 2019 and due June 15, 2029, or the 2029 Senior Notes;
3.375% senior notes, issued December 2, 2020 and due February 15, 2029, or the 3.375% 2029 Senior Notes;
3.625% senior notes, issued December 2, 2020 and due February 15, 2031, or the 2031 Senior Notes; and
3.875% senior notes, issued August 23, 2021 and due February 15, 2032, or the 2032 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% or 30% (depending on the series of Senior Notes) 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.
2027 Senior Notes
NRG may redeem some or all of the 2027 Senior 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 July 14, 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
July 15, 2022 to July 14, 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
July 15, 2023 to July 14, 2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
July 15, 2024 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Redemption
Percentage
103.313 %
102.208 %
101.104 %
100.000 %
129
2028 Senior Notes
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 of the notes redeemed, plus 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 50%. In addition, on or after January 15, 2023, NRG may redeem some or all of the notes at redemption prices expressed
as percentages of principal amount as set forth in the following table, plus accrued and unpaid interest on the notes redeemed to
the first applicable redemption date:
Redemption Period
January 15, 2023 to January 14, 2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
January 15, 2024 to January 14, 2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
January 15, 2025 to January 14, 2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
January 15, 2026 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Redemption
Percentage
102.875 %
101.917 %
100.958 %
100.000 %
5.250% 2029 Senior Notes
At any time prior to June 15, 2022, NRG may redeem up to 40% of the aggregate principal amount of the 2029 Senior
Notes, at a redemption price equal to 105.250% 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, provided that at least 50% of the aggregate
principal amount remains outstanding immediately after the occurrence of such redemption. At any time prior to June 15, 2024,
NRG may redeem all or a part of the 2029 Senior Notes, at a redemption price equal to 100% of the principal amount of the
notes redeemed, plus 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 102.625% of the note, plus interest payments due on the note through June 15, 2024 (excluding accrued but unpaid interest to
the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus 0.50%. In
addition, on or after June 15, 2024, 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
June 15, 2024 to June 14, 2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 15, 2025 to June 14, 2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 15, 2026 to June 14, 2027 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
June 15, 2027 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Redemption
Percentage
102.625 %
101.750 %
100.875 %
100.000 %
130
3.375% 2029 Senior Notes
At any time prior to February 15, 2024, NRG may redeem up to 40% of the aggregate principal amount of the 2029
Senior Notes, at a redemption price equal to 103.375% 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, provided that at least 50% of the aggregate
principal amount remains outstanding immediately after the occurrence of such redemption. At any time prior to February 15,
2024, NRG may redeem all or a part of the 2029 Senior Notes, at a redemption price equal to 100% of the principal amount of
the notes redeemed, plus 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 101.688% of the note, plus interest payments due on the note through February 15, 2024 (excluding accrued but unpaid
interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus
0.50%. In addition, on or after February 15, 2024, 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
February 15, 2024 to February 14, 2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
February 15, 2025 to February 14, 2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
February 15, 2026 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Redemption
Percentage
101.688 %
100.844 %
100.000 %
2031 Senior Notes
At any time prior to February 15, 2026, NRG may redeem up to 40% of the aggregate principal amount of the 2031
Senior Notes, at a redemption price equal to 103.625% 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, provided that at least 50% of the aggregate
principal amount remains outstanding immediately after the occurrence of such redemption. At any time prior to February 15,
2026, NRG may redeem all or a part of the 2031 Senior Notes, at a redemption price equal to 100% of the principal amount of
the notes redeemed, plus 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 101.813% of the note, plus interest payments due on the note through February 15, 2026 (excluding accrued but unpaid
interest to the redemption date), computed using a discount rate equal to the Treasury Rate as of such redemption date plus
0.50%. In addition, on or after February 15, 2026, 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
February 15, 2026 to February 14, 2027 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
February 15, 2027 to February 14, 2028 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
February 15, 2028 to February 14, 2029 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
February 15, 2029 and thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Redemption
Percentage
101.813 %
101.208 %
100.604 %
100.000 %
2032 Senior Notes
At any time prior to August 15, 2024, NRG may redeem up to 40% of the aggregate principal amount of the 2032 Senior
Notes, at a redemption price equal to 103.875% 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, provided that at least 50% of the aggregate
principal amount remains outstanding immediately after the occurrence of such redemption. At any time prior to February 15,
2027, NRG may redeem all or a part of the 2032 Senior Notes, at a redemption price equal to 100% of the principal amount of
the notes redeemed, plus 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 (A) the present value of (1) the redemption price of the note at
February 15, 2027 (such redemption price being set forth in the table appearing below in the column “Redemption Percentage
(If Sustainability Performance Target has not been satisfied and/or confirmed by External Verifier)” unless the Sustainability
Performance Target has been satisfied in respect of the year ended December 31, 2025 and the Company has provided
confirmation thereof to the Trustee together with a related confirmation by the External Verifier by the date that is at least 15
days prior to August 15, 2026 in which case the redemption price shall be as set forth in the column “Redemption Percentage
(If Sustainability Performance Target has been satisfied and confirmed by External Verifier)”) plus (2) interest payments due on
the note through February 15, 2027 (excluding accrued but unpaid interest to the redemption date) computed using a discount
rate equal to the Treasury Rate as of such redemption date plus 0.50%, over (B) the principal amount of the note. In addition, on
131
or after February 15, 2027, 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 during the twelve-month period beginning on February 15 of the years
indicated below, plus accrued and unpaid interest on the notes redeemed to the first applicable redemption date:
Year
2027 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2028 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2029 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2030 and thereafter . . . . . . . . . . . . . . . . . . . .
Receivables Facility
Redemption Percentage
(If Sustainability Performance Target has
been satisfied and confirmed by External
Verifier)
Redemption Percentage
(If Sustainability Performance Target has
not been satisfied and/or confirmed by
External Verifier)
101.938 %
101.292 %
100.646 %
100.000 %
102.188 %
101.458 %
100.729 %
100.000 %
On September 22, 2020, NRG Receivables LLC, a bankruptcy remote, special purpose, indirect wholly owned subsidiary,
entered into the Receivables Facility for an amount up to $750 million, subject to adjustments on a seasonal basis, with issuers
of asset-backed commercial paper and commercial banks (the "Lenders".) The assets of NRG Receivables LLC are first
available to satisfy the claims of the Lenders before making payments on the subordinated note and equity issued by NRG
Receivables LLC. The assets of NRG Receivables LLC are not available to the Company and its subsidiaries or creditors unless
and until distributed by NRG Receivables LLC. Under the Receivables Facility, certain indirect subsidiaries of the Company
sell their accounts receivables to NRG Receivables LLC, subject to certain terms and conditions. In turn, NRG Receivables
LLC grants a security interest in the purchased receivables to the Lenders as collateral for cash borrowings and issuances of
letters of credit. Pursuant to the Performance Guaranty, the Company has guaranteed, for the benefit of NRG Receivables and
the Lenders, the payment and performance by each indirect subsidiary of its respective obligations under the Receivables
Facility. The accounts receivables remain on the Company's consolidated balance sheet and any amounts funded by the Lenders
to NRG Receivables LLC will be reflected as short-term borrowings. Cash flows from the Receivables Facility are reflected as
financing activities in the Company's consolidated statements of cash flows. The Company will continue to service the accounts
receivables sold in exchange for a servicing fee.
On July 26, 2021, NRG Receivables LLC entered into the First Amendment to the Receivables Facility with a group of
conduit lenders and banks and Royal Bank of Canada, as Administrative Agent to, among other things, (i) increase the existing
revolving commitments by $50 million to an aggregate amount of $800 million, (ii) extend the maturity date until July 26,
2022, (iii) make certain adjustments to the pool of receivables through the Receivables Facility and certain related covenants
and (iv) provide for revised language relating to interest determination based on SOFR in case of a LIBOR cessation or the
occurrence of certain other trigger events. Borrowings by NRG Receivables LLC under the Receivables Facility bear interest as
defined under the Receivables Financing Agreement. The weighted average interest rate related to usage under the Receivables
Facility as of December 31, 2021 was 0.646%. As of December 31, 2021, there were no outstanding borrowings and there were
$400 million in letters of credit issued under the Receivables Facility.
Repurchase Facility
On September 22, 2020, the Company entered into the Repurchase Facility related to the Receivables Facility. Under the
Repurchase Facility, the Company can borrow up to $75 million, collateralized by a subordinated note issued by NRG
Receivables LLC to NRG Retail LLC in favor of the originating entities representing a portion of the balance of receivables
sold to NRG Receivables LLC under the Receivables Facility.
On July 26, 2021, the Company renewed its existing Repurchase Facility to, among other things, (i) extend the maturity
date to July 26, 2022 and (ii) provide for revised language relating to interest determination based on SOFR in case of a LIBOR
cessation or the occurrence of certain other trigger events. On February 9, 2022, the Company entered into amendments to its
existing Repurchase Facility to, among other things, (i) increase the size of the facility from $75 million to $150 million and (ii)
replace LIBOR with term SOFR as the benchmark for the pricing rate. The Repurchase Facility has no commitment fee and
borrowings will be drawn at SOFR + 1.30%. As of December 31, 2021, there were no outstanding borrowings under the
Repurchase Facility.
Senior Credit Facility
Revolving Credit Facility Modification
During the third quarter of 2020, the Company amended its existing credit agreement to, among other things, (i) increase
the existing revolving commitments in an aggregate amount of $802 million, and (ii) provide for a new tranche of revolving
commitments in an aggregate amount of $273 million with a maturity date of July 5, 2023. The maturity date of the new
revolving tranche of commitments may, upon request by the Company, and at the option of each applicable lender under the
132
new tranche be extended to May 28, 2024, which is the maturity date of the existing and increased commitments. Other than
with respect to the maturity date, the terms of all revolving commitments and loans made pursuant thereto are identical. The
increase in the existing commitments, and the commitments with respect to the new tranche were effective on August 20, 2020
and became available on January 5, 2021 upon the closing of the Direct Energy Acquisition. As of December 31, 2021, total
revolving commitments available, subject to usage, under the amended credit agreement was $3.7 billion.
Credit Default Swap Facility
On January 4, 2019, the Company entered into an $80 million credit agreement to issue letters of credit, which is currently
supporting the Cottonwood facility lease. Annual fees of 1.33% on the facility were paid quarterly in advance. On August 13,
2020, the agreement was amended permitting the Company to increase the size of the facility and fees on the facility were
adjusted to reflect the costs of the credit default swaps that serve as collateral for the facility. In order to increase the
Company’s collective collateral facilities in connection with the Direct Energy acquisition, NRG expanded the facility allowing
for the issuance of an additional $150 million of letters of credit as of December 31, 2020. As of December 31, 2021,
$222 million was issued under this facility.
Bilateral Letter of Credit Facilities
In December 2020 the Company entered into a series of Bilateral Letter of Credit Facilities to allow for the issuance of up
to $475 million of letters of credit. These facilities are uncommitted. As of December 31, 2021, $469 million was issued under
these facilities.
Put Option Agreement for Senior Debt Issuance
During the fourth quarter of 2020, the Company entered into a 3-year put option agreement with a Delaware trust formed
by the Company upon completion of the sale of $900 million pre-capitalized trust securities redeemable November 15, 2023
(the “P-Caps”). The Trust invested the proceeds from the sale of the P-Caps in a portfolio of principal and interest strips of U.S.
Treasury securities (the “Eligible Treasury Assets”). Under the put option agreement, NRG has the right, from time to time, to
issue to the Trust and to require the Trust to purchase from NRG, on one or more occasions (the “Issuance Right”), up to
$900 million aggregate principal amount of NRG’s 1.841% Senior Secured First Lien Notes due 2023 (the “P-Caps Secured
Notes”) in exchange for all or a portion of the Eligible Treasury Assets corresponding to the portion of the Issuance Right. NRG
will pay a semi-annual premium to the Trust at a rate of 1.65%.
In connection with the issuance of the P-Caps, on December 11, 2020, NRG entered into an amended and restated facility
agreement for the issuance of letters of credit (the “LC Agreement”) with Deutsche Bank Trust Company Americas as collateral
agent (the “Collateral Agent”) and administrative agent pursuant to which certain financial institutions (the “LC Issuers”) have
agreed to provide letters of credit in an aggregate amount not to exceed $874 million to support the operations of NRG and its
subsidiaries and minority investments, including to replace certain letters of credit and other credit support issued for the
account of entities acquired pursuant to the Direct Energy Acquisition. In addition, on December 11, 2020, the Trust entered
into an amended and restated pledge and control agreement (the “Pledge Agreement”), among NRG, the Trust and the
Collateral Agent for the LC Issuers, under which the Trust agreed to grant a pledge over the Eligible Treasury Assets in favor of
the Collateral Agent for the benefit of the LC Issuers. Pursuant to the LC Agreement and the Pledge Agreement, the Collateral
Agent is entitled to withdraw Eligible Treasury Assets from the Trust’s pledged account, following notice to NRG, in the event
NRG has failed to reimburse amounts drawn under any letter of credit issued pursuant to the LC Agreement, and the LC Issuers
have the right to instruct the Collateral Agent to enforce the pledge over the Eligible Treasury Assets upon the occurrence of
any event of default under the LC Agreement. The LC Agreement and the Pledge Agreement were available on January 5,
2021. As of December 31, 2021, $873 million of letters of credit were issued under the LC Agreement.
Tax Exempt Bonds
(In millions, except rates)
NRG Indian River Power 2020, tax exempt bonds, due 2040 . . . . . . . . .
NRG Indian River Power 2020, tax exempt bonds, due 2045 . . . . . . . . .
NRG Dunkirk 2020, 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 . . . . . . . . . . . . . . . . . . . .
As of December 31,
2021
2020
Interest Rate %
57 $
190
59
33
54
73
57
190
59
33
54
73
466
1.250
1.250
1.300
4.125
4.750
4.750
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
466 $
133
Dunkirk Bonds
On March 11, 2020, NRG issued $59 million in aggregate principal amount of NRG Dunkirk 2020 1.30% tax-exempt
refinancing bonds due 2042 (the "Dunkirk Bonds"). The Dunkirk Bonds are guaranteed on a first-priority basis by each of
NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The Dunkirk Bonds are secured
by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit
agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral
securing the Dunkirk Bonds will, at the request of NRG, be released if NRG satisfies certain conditions, including receipt of an
investment grade rating on its senior, unsecured debt securities from two out of the three rating agencies, subject to reversion if
those rating agencies withdraw their investment grade rating of the Dunkirk Bonds or any of NRG’s senior, unsecured debt
securities or downgrade such rating below investment grade. The Dunkirk Bonds are subject to mandatory tender and purchase
on April 3, 2023 and have a final maturity date of April 1, 2042.
NRG used the net proceeds from the offering to redeem during 2020 the existing principal amount of outstanding Dunkirk
Power LLC 5.875% tax exempt bonds due 2042.
Indian River Bonds
On December 17, 2020, NRG issued $57 million in aggregate principal amount of NRG Indian River 2020 1.25% tax-
exempt refinancing bonds due 2040 (the "IR 2040 Bonds") and $190 million aggregate principal amount of NRG Indian River
Power 2020 1.25% tax-exempt refinancing bonds due 2045 (the "IR 2045 Bonds") (together the "IR Bonds"). The IR Bonds are
guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit
agreement. The IR Bonds are secured by a first priority security interest in the same collateral that is pledged for the benefit of
the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG
and the guarantors. The collateral securing the IR Bonds will, at the request of NRG, be released if NRG satisfies certain
conditions, including receipt of an investment grade rating on its senior, unsecured debt securities from two out of the three
rating agencies, subject to reversion if those rating agencies withdraw their investment grade rating of the IR Bonds or any of
NRG’s senior, unsecured debt securities or downgrade such rating below investment grade. The IR Bonds are subject to
mandatory tender and purchase on October 1, 2025 and have final maturity dates of October 1, 2040 for the IR 2040 Bonds and
October 1, 2045 for the IR 2045 Bonds.
NRG used the net proceeds from the offering to redeem during 2020 the existing principal amounts of outstanding Indian
River Power 6.000% tax exempt bonds due 2040 and Indian River Power LLC 5.375% tax exempt bonds due 2045.
Note 14 — Asset Retirement Obligations
The Company's AROs are primarily related to the environmental obligations for nuclear decommissioning, mine
reclamation, ash disposal, site closures, 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 7, 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.
The following table represents the balance of ARO obligations as of December 31, 2021 and 2020, along with the
additions, reductions and accretion related to the Company's ARO obligations for the year ended December 31, 2021:
(In millions)
Nuclear
Decommission
Other(a)
Total
Balance as of December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
303 $
Revisions in estimates for current obligations . . . . . . . . . . . . . . . . . . . . . . . .
Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Spending for current obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
—
—
18
Balance as of December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
321 $
457 $
(36)
5
(51)
24
399 $
760
(36)
5
(51)
42
720
(a)
Total accretion expense related to asset retirement obligations included in the consolidated statement of cash flows includes accretion and revisions in
estimates for asset retirement liabilities on non-operating plants
134
Note 15 — Benefit Plans and Other Postretirement Benefits
NRG sponsors and operates defined benefit pension and other postretirement plans.
NRG pension benefits are available to eligible non-union and union employees through various defined benefit pension
plans. These benefits are based on pay, service history and age at retirement. Most pension benefits are provided through tax-
qualified plans. NRG also provides postretirement health and welfare benefits for certain groups of employees. Cost sharing
provisions vary by the terms of any applicable collective bargaining agreements.
NRG maintains three separate qualified pension plans, the NRG Pension Plan for Bargained Employees, the NRG Pension
Plan and the Pension Plan for Employees of Direct Energy Marketing Limited ("DEML"). Participation in the NRG Pension
Plan for Bargained Employees depends upon whether an employee is covered by a bargaining agreement. The NRG Pension
plan was frozen for non-union employees on December 31, 2018. The Pension Plan for Employees of DEML is closed to new
participants.
Due to updated assumptions as a result of ARPA, NRG does not expect to contribute to the Company's pension plans
in 2022.
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:
(In millions)
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 (credit)/cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(In millions)
Service cost benefits earned . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Interest cost on benefit obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of unrecognized prior service cost . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of unrecognized net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Curtailment loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net periodic benefit credit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Year Ended December 31,
Pension Benefits
2021
2020
2019
9 $
27
(66)
1
2
(27) $
10 $
38
(61)
5
—
(8) $
Year Ended December 31,
Other Postretirement Benefits
2021
2020
2019
— $
2
(10)
1
1
(6) $
— $
3
(14)
1
—
(10) $
10
46
(59)
3
—
—
1
3
(13)
—
—
(9)
135
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:
(In millions)
Benefit obligation at January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Acquired benefit obligation from Direct Energy . . . . . . . . . . . . .
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Actuarial (gain)/loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employee and retiree contributions . . . . . . . . . . . . . . . . . . . . . . . .
Curtailment loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefit payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign exchange translation . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefit obligation at December 31 . . . . . . . . . . . . . . . . . .
Fair value of plan assets at January 1 . . . . . . . . . . . . . . . . . . . . . .
Acquired fair value of plan assets from Direct Energy . . . . . . . . .
Actual return on plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employee and retiree contributions . . . . . . . . . . . . . . . . . . . . . . . .
Employer contributions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Benefit payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign exchange translation . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value of plan assets at December 31 . . . . . . . . . . . . .
Funded status at December 31 — excess of obligation over
As of December 31,
Pension Benefits
2021
2020
Other Postretirement
Benefits
2021
2020
1,489 $
74
9
27
(55)
—
—
(93)
1
1,452
1,272
64
85
—
7
(93)
1
1,336
1,397 $
—
10
38
126
—
—
(82)
—
1,489
1,150
—
193
—
11
(82)
—
1,272
90 $
19
—
2
—
3
1
(10)
—
105
—
—
3
7
(10)
—
—
93
—
—
3
—
3
—
(9)
—
90
—
—
—
3
6
(9)
—
—
assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(116) $
(217) $
(105) $
(90)
During the year ended December 31, 2021, the actuarial gain of $55 million on pension benefits was primarily driven by
increasing discount rates and changes in demographic assumptions.
During the year ended December 31, 2020, the actuarial loss of $126 million on pension benefits was driven by
decreasing discount rates and changes in demographic assumptions, partially offset by gains from life expectancy projection
updates.
Amounts recognized in NRG's balance sheets were as follows:
(In millions)
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Other non-current liabilities . . . . . . . . . . . . . . . . . . . . . . . .
As of December 31,
Pension Benefits
Other Postretirement
Benefits
2021
2020
2021
2020
— $
116
— $
217
7 $
98
5
85
Amounts recognized in NRG's accumulated OCI that have not yet been recognized as components of net periodic benefit
cost were as follows:
(In millions)
Net loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Prior service cost/(credit) . . . . . . . . . . . . . . . . . . . . . . . . . .
Total accumulated OCI . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
As of December 31,
Pension Benefits
Other Postretirement
Benefits
2021
2020
2021
2020
52 $
2
54 $
127 $
2
129 $
5 $
(19)
(14) $
6
(29)
(23)
136
Other changes in plan assets and benefit obligations recognized in OCI were as follows:
Year Ended December 31,
Pension Benefits
Other Postretirement
Benefits
2021
2020
2021
2020
(In millions)
Net actuarial gain . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Amortization of net actuarial loss . . . . . . . . . . . . . . . . . . . .
Amortization of prior service cost . . . . . . . . . . . . . . . . . . .
Effect of settlement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total recognized in OCI . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Net periodic benefit credit . . . . . . . . . . . . . . . . . . . . . . . . .
(72) $
(1)
—
(2)
(75) $
(27)
Net recognized in net periodic pension credit and OCI . . . $
(102) $
(6) $
(5)
—
—
(11) $
(8)
(19) $
— $
(1)
10
—
9 $
(6)
3 $
—
(1)
14
—
13
(10)
3
The following table presents the balances of significant components of NRG's pension plan:
(In millions)
Projected benefit obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Accumulated benefit obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair value of plan assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of December 31,
Pension Benefits
2021
2020
1,452 $
1,423
1,336
1,489
1,455
1,272
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:
(In millions)
Fair Value Measurements as of December 31, 2021
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
Significant
Observable Inputs
(Level 2)
Total
Common/collective trust investment — U.S. equity . . . . . . . . . . . . . . . . $
— $
221 $
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
—
—
13
69
110
340
—
Subtotal fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
13 $
740 $
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
221
69
110
340
13
753
78
405
65
35
Total fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1,336
137
(In millions)
Fair Value Measurements as of December 31, 2020
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
Significant
Observable Inputs
(Level 2)
Total
Common/collective trust investment — U.S. equity . . . . . . . . . . . . . . . . $
— $
284 $
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
—
—
13
113
151
258
—
Subtotal fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
13 $
806 $
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
284
113
151
258
13
819
45
289
84
35
Total fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1,272
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:
As of December 31,
Pension Benefits
Other Postretirement Benefits
2021
2020
2021
2020
Weighted-Average Assumptions
Discount rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest crediting rate . . . . . . . . . . . . . . . . . . . . . . . . . .
Rate of compensation increase . . . . . . . . . . . . . . . . . .
2.89 %
3.07 %
3.06 %
Health care trend rate . . . . . . . . . . . . . . . . . . . . . . . . .
—
2.56 %
3.12 %
3.00 %
—
2.89 %
2.54 %
1.94 %
— %
6.8% grading
to 4.4% in 2028
1.62 %
— %
7.2% grading to
4.5% in 2028
The following table presents the significant assumptions used to calculate NRG's benefit expense:
Weighted-Average
Assumptions
Discount rate . . . . . . . .
Interest crediting rate . .
Expected return on plan
assets . . . . . . . . . . . .
Rate of compensation
increase . . . . . . . . . . .
Pension Benefits
Other Postretirement Benefits
As of December 31,
2021
2020
2019
2021
2020
2019
2.55 %
3.13 %
3.26 % 4.38%/4.20%
3.66 %
—
2.81%
1.62 %
3.26 %
2.28 %
5.62 %
5.93 %
6.35 %
3.06 %
3.00 %
3.00 %
—
—
—
—
4.37 %
—
—
—
Health care trend rate . .
—
—
7.0% grading
to 4.4% in 2028
7.5% grading
to 4.5% in 2028
7.8% grading to
4.5% in 2025
—
138
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 and the AON Canada yield curve to select the appropriate discount rate assumption for its retirement plans. 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. Under the AA-AM yield curve, 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. The AON
Canada yield curve is based on high quality corporate bonds. Under the AON Canada yield curve, expected plan cash flows
were discounted using the the yield curve, and then a single rate is determined which produces an equivalent present value.
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.
The target allocations of NRG's pension plan assets were as follows for the year ended December 31, 2021:
U.S. equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-U.S. equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-core assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fixed Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17 %
13 %
15 %
55 %
Plan assets are currently invested in a diversified blend of equity and fixed-income investments. Furthermore, equity
investments are diversified across U.S., non-U.S., global, and emerging market equities, as well as among growth, value, small
and large capitalization stocks.
Investment risk and performance are monitored on an ongoing basis through quarterly portfolio reviews of each asset fund
class to a related performance benchmark, if applicable, and annual pension liability measurements. Performance benchmarks
are composed of the following indices:
U.S. equities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dow Jones U.S. Total Stock Market Index
Asset Class
Index
Non-U.S. equities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . MSCI All Country World Index
Non-core assets(a)
Fixed income securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Barclays Short, Intermediate and Long Credits/Barclays
Strips 20+ Index and FTSE Canada Universe Bond Index
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Various (per underlying asset class)
(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:
Other Postretirement Benefit
(In millions)
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2027-2031 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
139
Pension
Benefit Payments
Benefit Payments
96 $
94
91
87
86
396
Medicare Prescription
Drug Reimbursements
—
—
—
—
—
2
7 $
7
7
6
6
26
STP Defined Benefit Plans
NRG has a 44% undivided ownership interest in STP, as discussed further in Note 28, 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.
During 2019, STPNOC announced that the defined benefit pension plan would be frozen. As a result, during 2019, NRG
recognized a gain of $8 million related to the curtailment of benefits and an increase of $32 million to the pension liability was
recorded to other comprehensive income. The Company measures the fair value of its pension assets in accordance with
ASC 820, Fair Value Measurements and Disclosures, or ASC 820. As of December 31, 2021, the STPNOC defined benefit
pension plan was frozen to all employees.
For the years ended December 31, 2021 and December 31, 2020, NRG reimbursed STPNOC $17 million and $8 million,
respectively, for its contribution to the plans. In 2022, NRG expects to reimburse STPNOC $13 million for its contribution to
the plan.
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:
(In millions)
As of December 31,
Pension Benefits
Other Postretirement Benefits
2021
2020
2021
2020
Funded status — STPNOC benefit plans . . . . . . . . . . $
Net periodic benefit cost/(credit) . . . . . . . . . . . . . . . .
Other changes in plan assets and benefit obligations
recognized in other comprehensive income . . . . . .
(50) $
17
(51)
(99) $
7
22
(18) $
(4)
4
(20)
(4)
5
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:
(In millions)
Company contributions to defined contribution plans . . . . . . . . . . . . $
Year Ended December 31,
2021
2020
2019
25 $
22 $
22
140
Note 16 — Capital Structure
For the period from December 31, 2018 to December 31, 2021, 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, 2018 . . . . . . . . . . . . . . . . . . .
Shares issued under ESPP . . . . . . . . . . . . . . . . . . . . . . . . .
Shares issued under LTIPs . . . . . . . . . . . . . . . . . . . . . . . .
Share repurchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance as of December 31, 2019 . . . . . . . . . . . . . . . . . . .
Shares issued under ESPP . . . . . . . . . . . . . . . . . . . . . . . . .
Shares issued under LTIPs . . . . . . . . . . . . . . . . . . . . . . . .
Share repurchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance as of December 31, 2020 . . . . . . . . . . . . . . . . . . .
Shares issued under ESPP . . . . . . . . . . . . . . . . . . . . . . . . .
Shares issued under LTIPs . . . . . . . . . . . . . . . . . . . . . . . .
Share repurchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance as of December 31, 2021 . . . . . . . . . . . . . . . . . . .
Shares issued under LTIPs . . . . . . . . . . . . . . . . . . . . . . . .
Share repurchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance as of February 24, 2022 . . . . . . . . . . . . . . . . . . . .
Common Stock
Issued
420,288,886
—
1,601,904
—
421,890,790
—
1,167,058
—
423,057,848
—
489,326
—
423,547,174
288,491
—
423,835,665
Common Shares
Treasury
(136,638,847)
46,128
—
(36,301,882)
(172,894,601)
131,469
—
(6,062,783)
(178,825,915)
117,392
—
(1,084,752)
(179,793,275)
—
(1,889,151)
(181,682,426)
Outstanding
283,650,039
46,128
1,601,904
(36,301,882)
248,996,189
131,469
1,167,058
(6,062,783)
244,231,933
117,392
489,326
(1,084,752)
243,753,899
288,491
(1,889,151)
242,153,239
As of December 31, 2021, NRG had 14,372,743 shares of common stock reserved for the maximum number of shares
potentially issuable based on the conversion and redemption features of the long-term incentive plans.
Common stock dividends — The Company declared and paid $0.325, $0.30 and $0.03 quarterly dividend per common
share, or $1.30, $1.20 and $0.12 per share on an annualized basis for 2021, 2020 and 2019 respectively.
In the first quarter of 2020, NRG increased the annual dividend to $1.20 from $0.12 per share, as part of a long-term
capital allocation policy adopted in the fourth quarter of 2019, that targets allocating 50% of cash available for allocation
generated each year to growth investments and 50% to be returned to shareholders. The return of capital to shareholders is
expected to be completed through the increased dividend supplemented by share repurchases. The long-term capital allocation
policy targets an annual dividend growth rate of 7-9% per share in years subsequent to 2020. In 2021 and 2022, NRG increased
the annual dividend to $1.30 and $1.40 per share, representing an 8% increase each year. The Company's common stock
dividends are subject to available capital, market conditions, and compliance with associated laws, regulations and other
contractual obligations.
On January 21, 2022, NRG declared a quarterly dividend on the Company's common stock of $0.35 per share, or $1.40
per share on an annualized basis, payable on February 15, 2022, to stockholders of record as of February 1, 2022.
Employee Stock Purchase Plan — In March 2019, the Company reopened participation in the ESPP, which allows
eligible employees to elect to withhold between 1% and 10% of their eligible compensation to purchase shares of NRG
common stock at the lesser of 95% of its market value on the offering date or 95% of the fair market value on the exercise date.
An offering date will occur each April 1 and October 1. An exercise date will occur each September 30 and March 31. As of
December 31, 2021, there remained 2,636,199 shares of treasury stock reserved for issuance under the ESPP.
Share Repurchases — In 2018, the Company's board of directors authorized the Company to repurchase $1.5 billion of its
common stock. The Company executed $1.25 billion of these share repurchases in 2018, with the remaining $0.25 billion
completed in the first quarter of 2019. In 2019, the Company's board of directors authorized the Company to repurchase an
additional $1.25 billion of its common stock. The Company executed $1.194 billion of these share repurchases in 2019 and
completed the remaining $56 million under the 2019 authorization by February 27, 2020. The remaining repurchases in 2020
and were made under the long-term capital allocation policy discussed above. On December 6, 2021 the Company announced
that the Board of Directors has authorized $1 billion for share repurchases, as part of NRG’s Capital Allocation Program. The
program began in 2021 and will continue throughout 2022.
141
The following table summarizes the shares repurchases made during the years ended December 31, 2019, 2020 and 2021
as well as through February 24, 2022:
Total number of
shares and share
equivalents
purchased
Average
price paid
per share
and share
equivalent
Amounts paid for
shares and share
equivalents
purchased (in
millions)
2019 repurchases:
Repurchases under February 28, 2019 Accelerated Share Repurchase Agreement
Other repurchases(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equivalent shares purchased in lieu of tax withholdings on equity compensation
issuances(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Share Repurchases during 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020 repurchases:
Repurchases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equivalent shares purchased in lieu of tax withholdings on equity compensation
issuances(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Share Repurchases during 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021 repurchases:
Repurchases(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equivalent shares purchased in lieu of tax withholdings on equity compensation
issuances(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
9,438,671
26,863,211
936,928
37,238,810 $
38.79 $
6,062,783
711,248
6,774,031 $
33.05 $
1,084,752
249,013
Total Share Repurchases during 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2022 repurchases:
1,333,765 $
40.22 $
Repurchases made subsequent to December 31, 2021 . . . . . . . . . . . . . . . . . . . . . .
Equivalent shares purchased in lieu of tax withholdings on equity compensation
issuances(b)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,889,151
130,674
Total share repurchases January 1, 2021 through February 24, 2022 . . . . . . . . . . .
2,019,825 $
40.26 $
400
1,008
36
1,444
197
27
224
44
9
53
76
6
82
(a)
(b)
Includes $5 million and $4 million accrued as of December 31, 2021 and December 31,2019, respectively
NRG elected to pay cash for tax withholding on equity awards instead of issuing actual shares to management. The average price per equivalent shares
withheld was $43.08, $37.50, $38.23 and $38.78 in 2022, 2021, 2020 and 2019, respectively. See Note 21, Stock-Based Compensation, for further
discussion of the equity awards
142
Note 17 — 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, 2021:
(In millions, except percentages)
Name:
Gladstone . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ivanpah Master Holdings, LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Watson Cogeneration Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Midway-Sunset Cogeneration Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Economic
Interest
Investment
Balance(a)
37.5 % $
54.5 %
49.0 %
50.0 %
Total equity investments in affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Petra Nova Parish Holdings, LLC(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
50.0 % $
127
4
14
12
157
(16)
(a)
(b)
As of December 31, 2021, the carrying value of NRG's equity method investment was $116 million lower than the underlying net assets of the investees.
The basis difference is being amortized into net income over the remaining estimated useful lives of the underlying net assets. The basis difference is
primarily due to impairments booked on Petra Nova, but not booked at the project level, as well as differences related to the deconsolidations of Ivanpah
and the treatment of certain deferred tax assets
The Company continues to account for Petra Nova under the equity method due to the fact that NRG still has a financial guaranty. As a result, the
Company continues to record losses for a negative equity method investment. As of December 31, 2021, NRG recorded $16 million to other non-current
liabilities. Refer to Note 11, Asset Impairments, for discussion of NRG's investment in Petra Nova Parish Holdings, LLC
(In millions)
As of December 31,
2020
2021
Undistributed earnings from equity investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
33 $
30
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.
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
$127 million as of December 31, 2021.
Entities that are Consolidated
The Company has a controlling financial interest that has been identified as a VIE under ASC 810 in NRG Receivables
LLC, which has entered into financing transactions related to the Receivables Facility as further described in Note 13, Long-
term Debt and Finance Leases.
143
The summarized financial information for the Company's consolidated VIEs consisted of the following:
(In millions)
December 31, 2021 December 31, 2020
Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
939 $
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
939
78
Net assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
861 $
647
2
649
78
571
Note 18 — Income Per Share
Basic income per common share is computed by dividing net income 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 per share is computed in a manner consistent with that of basic income 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 relative performance stock units,
non-vested restricted stock units, market stock units and non-qualified stock options are not considered outstanding for
purposes of computing basic income per share. However, these instruments are included in the denominator for purposes of
computing diluted income per share under the treasury stock method. As of December 31, 2021, 2020 and 2019, the
Convertible Senior Notes were convertible, under certain circumstances, into the Company’s common stock, cash or
combination thereof (at NRG's option). There was no dilutive effect for the Convertible Senior Notes due to the Company’s
expectation, as of such dates, to settle the liability in cash. On February 22, 2022, the Company irrevocably elected to eliminate
the right to settle conversions only in shares of the Company's common stock, such that any conversion after such date will be
settled in cash or a combination of cash and the Company's common stock.
The reconciliation of NRG's basic income per share to diluted income per share is shown in the following table:
(In millions, except per share amounts)
Basic income per share attributable to NRG Energy, Inc;
Year Ended December 31,
2020
2019
2021
Net income attributable to NRG Energy, Inc. common stockholders . . . . . . . . . . $
2,187 $
510 $
Weighted average number of common shares outstanding-basic . . . . . . . . . . . . . . . . . . . .
245
245
Income per weighted average common share — basic . . . . . . . . . . . . . . . . . . . . . . . . . . . $
8.93 $
2.08 $
Diluted income per share attributable to NRG Energy, Inc;
Net income attributable to NRG Energy, Inc. common stockholders . . . . . . . . . . $
2,187 $
510 $
Weighted average number of common shares outstanding-basic . . . . . . . . . . . . . . . . . . . .
Incremental shares attributable to the issuance of equity compensation (treasury stock
method) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average number of common shares outstanding-diluted . . . . . . . . . . . . . . . . . . .
245
—
245
245
1
246
4,438
262
16.94
4,438
262
2
264
Income per weighted average common share — diluted . . . . . . . . . . . . . . . . . . . . . . . . . $
8.93 $
2.07 $
16.81
As of December 31, 2021, 2020 and 2019 the Company had an insignificant number of outstanding equity instruments
that are anti-dilutive and were not included in the computation of the Company’s diluted income per share.
Note 19 — Segment Reporting
The Company’s segment structure reflects how management makes financial decisions and allocates resources. The
Company manages its operations based on the combined results of the retail and wholesale generation businesses with a
geographical focus.
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.
The acquired operations of Direct Energy are integrated into the existing NRG segment structure. Domestic customer and
market operations are combined into the corresponding geographical segments of Texas, East and West/Services/Other. The
West/Services/Other segment includes activity related to the Canadian operations as well as the services businesses.
144
26,989
22,566
785
544
23,895
247
3,341
17
63
(77)
(485)
2,859
672
2,187
157
269
1,795
23,182
In February 2019, the Company completed the sale and deconsolidation of the South Central Portfolio and Carlsbad.
Refer to Note 4, Acquisitions, Discontinued Operations and Dispositions, for further discussion.
The Company had no customer that comprised more than 10% of the Company's consolidated revenues during the years
ended December 31, 2021, 2020 and 2019.
Intersegment sales are accounted for at market.
(In millions)
Operating revenues(a)
Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . .
Impairment losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total operating cost and expenses . . . . . . . . . . . . . . . . .
Gain on sale of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity in (losses)/earnings of unconsolidated affiliates . . . . .
Other income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on debt extinguishment . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income/(loss) from continuing operations before
income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
For the Year Ended December 31, 2021
Texas
East
West/
Services/
Other
Corporate(a)
Eliminations
Total
10,293 $
13,033 $
3,653 $
— $
10 $
10,257
3,466
8,692
331
—
9,023
19
1,289
(3)
8
—
(1)
338
535
11,130
—
1,903
—
7
—
(1)
1,293
—
1,909
—
88
9
3,563
17
107
20
3
—
(28)
102
19
141
28
—
169
211
42
—
59
(77)
(469)
(445)
653
10
—
—
10
—
—
—
(14)
—
14
—
—
Net income/(loss) attributable to NRG Energy, Inc. . . . $
1,293 $
1,909 $
83 $
(1,098) $
— $
Balance sheet
Equity investments in affiliates . . . . . . . . . . . . . . . . . . . . . . . $
Capital expenditures
Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(a) Inter-segment sales and inter-segment net derivative
— $
— $
157 $
— $
— $
153
751
50
853
21
191
45
—
—
—
12,265 $
13,673 $
4,816 $
19,081 $
(26,653) $
gains and losses included in operating revenues . . . . . . . . $
5 $
(18) $
3 $
— $
— $
(10)
145
9,093
7,481
435
75
7,991
3
1,105
17
(18)
67
(9)
(401)
761
251
510
346
230
579
For the Year Ended December 31, 2020
Texas
East
West/
Services/
Other
Corporate(a)
Eliminations
Total
(In millions)
Operating revenues(a)
Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . .
Impairment losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total operating cost and expenses . . . . . . . . . . . . . . . . .
(Loss)/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 . . . . . . . . . . . . . . . . . . . . . . . . .
6,309 $
2,258 $
530 $
— $
(4) $
5,249
227
14
5,490
—
819
(12)
(18)
11
—
—
800
—
1,758
138
—
1,896
—
362
—
—
7
(4)
(14)
351
(1)
421
36
61
518
(2)
10
29
—
8
(5)
(3)
39
2
57
34
—
91
5
(86)
—
—
41
—
(384)
(429)
250
(4)
—
—
(4)
—
—
—
—
—
—
—
—
—
Net income attributable to NRG Energy, Inc. . . . . . . . . $
800 $
352 $
37 $
(679) $
— $
Balance sheet
Equity investments in affiliates . . . . . . . . . . . . . . . . . . . . . . . $
Capital expenditures
Goodwill(b) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(a) Inter-segment sales and inter-segment net derivative
gains and losses included in operating revenues . . . . . . . . $
(13) $
— $
359 $
— $
— $
130
324
45
240
30
15
25
—
—
—
7,641 $
1,790 $
1,679 $
11,152 $
(7,360) $
14,902
6 $
(6) $
4 $
— $
— $
4
(b) Goodwill was allocated based on the regions in which the business operates and are expected to benefit using a relative fair value approach . . . . . . . . . . . .
(In millions)
Operating revenues(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . .
Impairment losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total operating cost and expenses . . . . . . . . . . . . . . . .
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 expense/(benefit) . . . . . . . . . . . . . . . . . . . . . . . .
Net income from continuing operations . . . . . . . . . . . .
Gain from discontinued operations, net of income tax . . . . .
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Net income attributable to noncontrolling interests
and redeemable noncontrolling interests . . . . . . . . . . . . . . .
For the Year Ended December 31, 2019
Texas
East
West/
Services/
Other
Corporate(a)
Eliminations
Total
7,069 $
2,262 $
497 $
— $
(7) $
5,821
188
1
6,010
—
1,059
(4)
(103)
20
—
—
972
—
972
—
972
—
1,843
117
—
1,960
1
303
—
—
6
—
(18)
291
2
289
—
289
—
453
37
4
494
—
3
6
—
10
(3)
(10)
6
1
5
—
5
3
50
31
—
81
6
(75)
—
(5)
30
(48)
(385)
(483)
(3,337)
2,854
321
3,175
—
(7)
—
—
(7)
—
—
—
—
—
—
—
—
—
—
—
—
—
9,821
8,160
373
5
8,538
7
1,290
2
(108)
66
(51)
(413)
786
(3,334)
4,120
321
4,441
3
Net income attributable to NRG Energy, Inc. . . . . . . . $
972 $
289 $
2 $
3,175 $
— $
4,438
(a) Inter-segment sales and inter-segment net derivative
gains and losses included in operating revenues
$
1 $
8 $
(2) $
— $
— $
7
146
Note 20 — Income Taxes
The income tax provision from continuing operations consisted of the following amounts:
(In millions, except effective income tax rate)
Current
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total — current
Deferred
U.S. Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total — deferred
Total income tax expense/(benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Year Ended December 31,
2021
2020
2019
48
3
51
569
36
16
621
672
$
$
22
4
26
168
60
(3)
225
251
$
$
2
4
6
(3,000)
(340)
—
(3,340)
(3,334)
Effective income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
23.5 %
33.0 %
(424.2) %
During the year ended December 31, 2019, NRG released the majority of its valuation allowance against its U.S. federal
and state deferred tax assets, resulting in a non-cash benefit to income tax expense of approximately $3.5 billion. In making the
determination to release the majority of the valuation allowance as of December 31, 2019, the Company evaluated a number of
factors, including its recent history of pre-tax earnings, utilization of $593 million of NOLs in 2019, as well as its forecasted
future pre-tax earnings. Based on this evaluation, the Company determined that the majority of its future tax benefits are more-
likely-than-not to be realized. Given the Company’s current level of pre-tax earnings and forecasted future pre-tax earnings, the
Company expects to generate income before taxes in the U.S. in future periods at a level that would fully utilize its U.S. federal
NOL carryforwards and the majority of its state NOL carryforwards prior to their expiration.
On March 27, 2020, the Senate passed the CARES Act to provide emergency relief related to the COVID-19 pandemic.
The CARES Act contains federal income tax provisions which, among other things: (i) increases the amount of interest expense
that businesses are allowed to deduct by increasing the adjusted taxable income limitation from 30% to 50% for tax years that
begin in 2019 and 2020; (ii) permits businesses to carry back to each of the five tax years NOLs arising from tax years
beginning after December 31, 2017 and before January 1, 2020; and (iii) temporarily removes the 80% limitation on NOLs until
tax years beginning after 2020. The CARES Act provisions did not have a material impact on the tax positions of the Company.
The following represented the domestic and foreign components of income from continuing operations before income
taxes:
(In millions)
Year Ended December 31,
2021
2020
2019
U.S. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2,759 $
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
100
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2,859 $
749 $
12
761 $
771
15
786
147
Reconciliations of the U.S. federal statutory tax rate to NRG's effective tax rate were as follows:
(In millions, except effective income tax rate)
2021
2020
2019
Year Ended December 31,
Income from continuing operations before income taxes . . . . . . . . . . . . $
2,859
$
Tax at federal statutory tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign rate differential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Permanent differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred impact of state tax rate changes . . . . . . . . . . . . . . . . . . . . . . .
Recognition of uncertain tax benefits . . . . . . . . . . . . . . . . . . . . . . . . . .
Return to provision adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
600
(3)
111
8
(29)
(10)
(10)
5
—
$
761
160
—
18
8
24
2
3
36
—
786
165
—
13
(9)
(3,492)
12
(10)
—
(13)
Income tax expense/(benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
672
$
251
$
(3,334)
Effective income tax rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
23.5 %
33.0 %
(424.2) %
For the year ended December 31, 2021, NRG's effective income tax rate was higher than the federal statutory tax rate of
21% primarily due to state tax expense partially offset by tax benefits from the revaluation of state deferred tax assets, valuation
allowance, and settlements of uncertain tax positions.
For the year ended December 31, 2020, NRG's effective income tax rate was higher than the federal statutory tax rate of
21% primarily due to state tax expense, the recognition of state valuation allowance on NOLs, and return to provision
adjustments.
For the year ended December 31, 2019, NRG's effective income tax rate was lower than the federal statutory tax rate of
21% primarily due to the tax benefit from the release of the valuation allowance.
148
The temporary differences, which gave rise to the Company's deferred tax assets and liabilities consisted of the following:
(In millions)
Deferred tax assets:
Deferred compensation, accrued vacation and other reserves . . . . . . . . . . . . . . . . . . . . . . . $
Difference between book and tax basis of property . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pension and other postretirement benefits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Bad debt reserve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivatives, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
U.S. Federal net operating loss carryforwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign net operating loss carryforwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State net operating loss carryforwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Federal and state tax credit carryforwards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Federal benefit on state uncertain tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest disallowance carryforward per §163(j) of the Tax Act . . . . . . . . . . . . . . . . . . . . .
Inventory obsolescence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred tax liabilities:
Emissions allowances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivatives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangibles amortization (excluding goodwill) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity method investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Convertible Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deferred tax assets less deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . .
Valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total net deferred tax assets, net of valuation allowance . . . . . . . . . . . . . . . . . . . . . . . $
As of December 31,
2021
2020
114 $
436
65
7
168
—
1,773
112
328
384
3
6
9
15
3,420
20
591
40
363
62
14
1,090
2,330
(248)
2,082 $
79
357
86
10
16
11
2,117
102
351
384
4
4
6
10
3,537
21
—
29
2
156
16
224
3,313
(266)
3,047
The following table summarizes NRG's net deferred tax position as presented in the consolidated balance sheets:
(In millions)
Deferred tax asset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Deferred tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net deferred tax asset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
As of December 31,
2021
2020
2,155 $
(73)
2,082 $
3,066
(19)
3,047
The primary drivers for the decrease in the net deferred tax asset from $3.0 billion as of December 31, 2020 to $2.1 billion
as of December 31, 2021 are an increase in mark-to-market book gains and step-up in basis of book intangibles associated with
the acquisition of Direct Energy.
Deferred tax assets and valuation allowance
Net deferred tax balance — As of December 31, 2021 and 2020, NRG recorded a net deferred tax asset, excluding
valuation allowance, of $2.3 billion and $3.3 billion, respectively. The Company believes certain state net operating losses may
not be realizable under the more-likely-than-not measurement and as such, a valuation allowance was recorded as of December
31, 2021 as discussed below.
NOL carryforwards — As of December 31, 2021, the Company had tax-effected cumulative U.S. NOLs consisting of
carryforwards for federal and state income tax purposes of $1.8 billion and $328 million, respectively. The Company estimates
it will need to generate future taxable income to fully realize the net federal deferred tax asset before the expiration of certain
carryforwards commences in 2031. In addition, NRG has tax-effected cumulative foreign NOL carryforwards of $112 million
with no expiration date.
149
Valuation allowance — As of December 31, 2021, the Company's tax-effected valuation allowance was $248 million,
consisting of state NOL carryforwards and foreign NOL carryforwards. The valuation allowance was recorded based on the
assessment of cumulative and forecasted pre-tax book earnings and the future reversal of existing taxable temporary
differences.
Taxes Receivable and Payable
As of December 31, 2021, NRG recorded a current net federal receivable of $16 million, comprised of refunds due from
the IRS, a current net state tax payable of $13 million that is primarily comprised of Texas margin tax, and a current net foreign
receivable of $11 million due to filings of Canadian amended returns as well as prepayments of estimated taxes.
Uncertain tax benefits
NRG has identified uncertain tax benefits with after-tax value of $13 million and $15 million as of December 31, 2021
and 2020, for which NRG has recorded a non-current tax liability of $14 million and $18 million, respectively. The Company
recognizes interest and penalties related to uncertain tax benefits in income tax expense. The Company recognized an
immaterial amount of interest expense for the year ended December 31, 2021, and $1 million for the years ended 2020 and
2019. As of December 31, 2021 and 2020, NRG had cumulative interest and penalties related to these uncertain tax benefits of
$1 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 and Canada.
The Company is no longer subject to U.S. federal income tax examinations for years prior to 2018. With few exceptions,
state and Canadian income tax examinations are no longer open for years before 2013.
The following table summarizes uncertain tax benefits activity:
(In millions)
Balance as of January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Increase due to current year positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase due to acquired balance from Direct Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlements, payments and statute closure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Uncertain tax benefits as of December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
As of December 31,
2021
2020
15 $
4
9
(15)
13 $
15
3
—
(3)
15
Note 21 — 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, 2021 and 2020, a total of 25,000,000 shares of NRG common stock were authorized for issuance under the
NRG LTIP. There were 8,871,874 and 9,385,730 shares of common stock remaining available for grants under the NRG LTIP
as of December 31, 2021 and 2020, 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, 2021 and 2020, there were 20,131 and 78,903 shares of
common stock remaining available for grants under the NRG GenOn LTIP, respectively.
150
Restricted Stock Units
As of December 31, 2021, RSUs granted under the Company's LTIPs typically have three-year graded vesting schedules
beginning on the grant date. Fair value of the RSUs granted during 2021 and 2020 is derived from the closing price of NRG
common stock on the grant date. The following table summarizes the Company's non-vested RSU awards and changes during
the year:
Non-vested at December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested at December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Units
519,514 $
479,415
(49,816)
(279,161)
669,952
Weighted Average Grant
Date Fair Value per Unit
35.87
39.00
37.41
34.18
38.69
The total fair value of RSUs vested during the years ended December 31, 2021, 2020 and 2019 was $12 million, $17
million and $36 million, respectively. The weighted average grant date fair value of RSUs granted during the years ended
December 31, 2021, 2020 and 2019 was $39.00, $38.05 and $37.37, respectively.
Deferred Stock Units
DSUs represent the right of a participant to be paid one share of NRG common stock at the end of a deferral period
established under the terms of the award. DSUs granted under the Company's LTIPs are fully vested at the date of issuance.
Fair value of the DSUs, which is based on the closing price of NRG common stock on the date of grant, is recorded as
compensation expense in the period of grant.
The following table summarizes the Company's outstanding DSU awards and changes during the year:
Outstanding at December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Units
342,706 $
64,512
Weighted Average Grant
Date Fair Value per Unit
25.37
32.27
Converted to Common Stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Outstanding at December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(23,090)
384,128
30.92
26.11
The aggregate intrinsic values for DSUs outstanding as of December 31, 2021, 2020 and 2019 were approximately
$17 million, $13 million and $13 million, respectively. The aggregate intrinsic values for DSUs converted to common stock for
the years ended December 31, 2021, 2020 and 2019 were $1 million, $2 million and $2 million, respectively. The weighted
average grant date fair value of DSUs granted during the years ended December 31, 2021, 2020 and 2019 was $32.27, $35.59
and $34.84, 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. PSUs include RPSUs and MSUs. As of December 31, 2021, non-vested
PSUs consist of 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(a). 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.
(a) For RPSU's granted in 2022 and forward the peer group will consist of the companies that comprise the Standard & Poor’s 500 Index on the first day of the
performance period.
151
The following table summarizes the Company's non-vested PSU awards and changes during the year:
Non-vested at December 31, 2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested at December 31, 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Units
793,561 $
426,768
(93,031)
(396,793)
730,505
Weighted Average Grant-
Date Fair Value per Unit
41.69
46.78
47.21
35.32
47.40
The weighted average grant date fair value of PSUs granted during the years ended December 31, 2021, 2020 and 2019,
was $46.78, $23.75 and $22.50, 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021(a)
RPSUs
34.05 %
3
0.17 %
2020
RPSUs
2019
RPSUs
30.15 %
3
1.58 %
40.72 %
3
2.45 %
(a) Assumptions pertain to the main award granted in January 2021. Additional 60,815 RPSUs were granted in September 2021 with a risk
free rate of 0.42% and expected volatility of 37.38%
For the years ended December 31, 2021 and 2020, 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.
Non-Qualified Stock Options
All NQSOs granted under the Company's LTIP were fully vested as of December 31, 2021, 2020 and 2019. No NQSOs
were granted in 2021, 2020 or 2019. NRG recognized compensation costs for NQSOs over the requisite service period for the
entire award. No compensation expense was recognized during 2021, 2020 or 2019 as it was fully recognized in prior years.
The maximum contractual term is 10 years for NRG's outstanding NQSOs.
The following table summarizes the Company's NQSO activity and changes during the year:
Shares
Weighted Average
Exercise Price
Weighted Average
Remaining Contractual
Term (in years)
Aggregate
Intrinsic Value
(in millions)
Outstanding at December 31, 2020 . . . . . . . . . . . .
Expired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Outstanding at December 31, 2021 . . . . . . . . . . .
Exercisable at December 31, 2021 . . . . . . . . . . . .
77,047 $
(4,800)
(54,377)
17,870
17,870
25.13
29.08
26.44
20.07
20.07
0.5 $
1
0.2
0.2
—
—
The following table summarizes the total intrinsic value of options exercised and the cash received from the exercises of
options:
(In millions)
Year Ended December 31,
2021
2020
2019
Total intrinsic value of options exercised . . . . . . . . . . . . . . . . . . . . . . . . . $
Cash received from options exercised . . . . . . . . . . . . . . . . . . . . . . . . . . .
1 $
1
1 $
1
2
3
152
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, 2021, for each of the types of awards issued under the LTIPs. Minimum tax withholdings of $9 million, $27
million, and $36 million for the years ended December 31, 2021, 2020, and 2019, respectively, are reflected as a reduction to
additional paid-in capital on the Company's consolidated balance sheets.
(In millions, except weighted average data)
Award
RSUs . . . . . . . . . . . . . . . . . . . . . . . . . . $
DSUs . . . . . . . . . . . . . . . . . . . . . . . . . .
RPSUs . . . . . . . . . . . . . . . . . . . . . . . . .
PRSUs(a) . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . $
Tax detriment/(benefit) recognized . . . $
Compensation Expense
Year Ended December 31,
Non-vested Compensation Cost
Unrecognized
Total Cost
Weighted Average
Recognition Period
Remaining (In years)
As of December 31,
2021
2020
2019
2021
2021
9 $
2
9
7
27 $
2 $
9 $
2
10
6
27 $
(9) $
9 $
2
10
11
32 $
(12)
16
—
15
10
41
1.80
0.00
1.19
1.52
(a)
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
Note 22 — Related Party Transactions
NRG provides services to some of its related parties, who are accounted for as equity method investments, under
operations and maintenance agreements. Fees for the services under these agreements include recovery of NRG's costs of
operating the plants. Certain agreements also include fees for administrative service, a base monthly fee, profit margin and/or
annual incentive bonus.
The following table summarizes NRG's material related party transactions with third party affiliates:
(In millions)
Revenues from Related Parties Included in Operating Revenues
Gladstone . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Ivanpah(a) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Midway-Sunset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(a)
Includes fees under project management agreements with each project company
Note 23 — Commitments and Contingencies
Certain Fuel and Transportation Commitments
Year Ended December 31,
2021
2020
2019
4 $
39
6
49 $
4 $
43
5
52 $
4
35
5
44
NRG has entered into long-term contractual arrangements to procure certain fuel and transportation services for the
Company's generation assets.
As of December 31, 2021, the Company's minimum commitments under such outstanding agreements are estimated as
follows:
Period
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(In millions)
122
54
63
62
51
26
378
(a)
Actual fuel and transportation purchases are significantly higher than these estimated minimum unconditional long-term firm commitments with
remaining term in excess of one year
153
For the years ended December 31, 2021, 2020 and 2019, the costs of certain fuel and transportation were $0.6 billion,
$0.5 billion and $0.6 billion, respectively.
Purchased Energy Commitments
NRG has long-term contractual commitments related to electricity and natural gas products, including power purchases,
gas transportation and storage of various quantities and durations, and renewable purchased power agreements under PPAs with
third-party project developers, which are accounted for as NPNS. These contracts are not included in the consolidated balance
sheet as of December 31, 2021. Minimum purchase commitment obligations are as follows as of December 31, 2021:
Period
(In millions)
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2024 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2025 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2026 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total(a)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
1,566
1,036
617
382
289
1,071
4,961
(a)
Actual energy purchases are significantly higher than these estimated minimum unconditional long-term firm commitments with remaining term in
excess of one year
For the years ended December 31, 2021, 2020 and 2019, the costs of purchased energy were $12.8 billion, $1.8 billion
and $2.6 billion, respectively.
First Lien Structure
NRG has granted first liens to certain counterparties on a substantial portion of property and assets owned by NRG and
the guarantors of its senior debt. 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 hedges. To the
extent that the underlying hedge positions for a counterparty are out-of-the-money to NRG, the counterparty would have a
claim under the first lien program. As of December 31, 2021, hedges under the first lien were out-of-the-money for NRG on a
counterparty aggregate basis.
Nuclear Insurance
STP maintains required insurance coverage for liability claims arising from nuclear incidents pursuant to the Price-
Anderson Act. The current liability limit per incident is $13.8 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
adjustment expected to be effective no later than November 1, 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 $13.3 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, per reactor. In addition, the U.S.
Congress retains the ability to impose additional financial requirements on the nuclear industry to pay liability claims that
exceed $13.8 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 $2.8 billion in limits for nuclear events and $1.0 billion in
limits for non-nuclear events. The nuclear event limit remains the maximum available from NEIL. The upper $1.3 billion in
nuclear events limits (excess of the first $1.5 billion in nuclear events 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 primary 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
$2 million per week per unit up to a maximum of $216 million nuclear and $144 million non-nuclear, and is subject to an eight-
154
week waiting period. Accidental Outage coverage amounts decrease in the event more than one unit at a station is out of service
due to a common accident. 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 ensure 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. All insurance coverage is subject to various sub
limits and significant deductibles.
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 accruals 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 accrual for the applicable legal matters, including regulatory and
environmental matters as further discussed in Note 24, Regulatory Matters, and Note 25, Environmental Matters. 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 accruals 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.
Environmental Lawsuits
Sierra club et al. v. Midwest Generation LLC — In 2012, several environmental groups filed a complaint against Midwest
Generation with the Illinois Pollution Control Board ("IPCB") alleging violations of environmental law resulting in
groundwater contamination. In June 2019, the IPCB found that Midwest Generation violated the law because it had improperly
handled coal ash at four facilities in Illinois and caused or allowed coal ash constituents to impact groundwater. On September
9, 2019, Midwest Generation filed a Motion to Reconsider numerous issues, which the court granted in part and denied in part
on February 6, 2020. The IPCB will hold hearings to determine the appropriate relief. Midwest Generation has been working
with the Illinois EPA to address the groundwater issues since 2010.
Consumer Lawsuits
Similar to other energy service companies (“ESCOs”) operating in the industry, from time-to-time, the Company and/or
its subsidiaries may be subject to consumer lawsuits in various jurisdictions where they sell natural gas and electricity.
Variable Price Cases — In the cases set forth below, referred to as the Variable Price Cases, such actions involve
consumers alleging that one of the Company’s ESCOs promised that consumers would pay the same or less than they would
have paid if they stayed with their default utility or previous energy supplier. The underlying claims of each case are similar and
the Company continues to deny the allegations and is vigorously defending these matters. These matters were known and
accrued for at the time of each acquisition.
XOOM Energy
XOOM Energy is a defendant in a putative class action lawsuit pending in New York. This case is in the discovery phase.
Direct Energy
There are three putative class actions pending against Direct Energy: (1) Linda Stanley v. Direct Energy (S.D.N.Y Apr.
2019) - The parties mediated in June and agreed on a settlement. On November 16, 2021, the Court granted preliminary
approval of the settlement. The final approval hearing will be held on April 5, 2022. It may take several months to determine
the final payout amount; (2) Martin Forte v. Direct Energy (N.D.N.Y. Mar. 2017) - The Court recently granted Direct Energy’s
Motion for Summary Judgment effectively ending the matter at the district court level. It is likely that the plaintiff will appeal;
155
however, it is unlikely plaintiff will prevail; (3) Richard Schafer v. Direct Energy (W.D.N.Y. Dec. 2019; on appeal 2nd Cir.
N.Y.) - The Court granted limited discovery that will end April 29, 2022. Summary judgement briefing is due on May 20, 2022.
Telephone Consumer Protection Act ("TCPA") Cases — In the cases set forth below, referred to as the TCPA Cases, such
actions involve consumers alleging violations of the Telephone Consumer Protection Act of 1991, as amended, by receiving
calls, texts or voicemails without consent in violation of the federal Telemarketing Sales Rule, and/or state counterpart
legislation. The underlying claims of each case are similar. The Company denies the allegations asserted by plaintiffs and
intends to vigorously defend these matters. These matters were known and accrued for at the time of the acquisition.
There are two putative class actions pending against Direct Energy: (1) Brittany Burk v. Direct Energy (S.D. Tex. Feb.
2019) - The Court denied Plaintiff's Motion for Class Certification and Motion for Substitution of a New Plaintiff on September
20, 2021. The parties reached a settlement of the plaintiff's individual claims and the Court has conditionally dismissed the
matter; and (2) Matthew Dickson v. Direct Energy (N.D. Ohio Jan. 2018) - Direct Energy has filed a Third-Party Petition
against its vendor, Total Marketing Concepts, LLC, who placed voicemails without consent from Direct Energy and in violation
of the parties’ agreement. The case was stayed pending the outcome of an appeal to the Sixth Circuit based on the
unconstitutionality of the TCPA during the period from 2015-2020. The Sixth Circuit found the TCPA was in effect during that
period and remanded the case back to the trial court. Direct Energy refiled its motions along with supplements.
Winter Storm Uri Lawsuits
The Company has been named in certain property damage and wrongful death claims that have been filed in connection
with Winter Storm Uri. At this time, the Company is unable to determine the extent or impact of these various litigation matters
due to their preliminary nature. The Company intends to vigorously defend these matters.
Indemnifications and Other Contractual Arrangements
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 LaGen in the United States
District Court for the Middle District of Louisiana. The plaintiffs claimed 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 sought damages for the alleged improper charges and a declaration as to which charges were proper under the
contract. In February 2020, the court dismissed this lawsuit without prejudice for lack of subject matter jurisdiction. On March
17, 2020, plaintiffs filed a lawsuit in the Nineteenth Judicial District Court for the Parish of East Baton Rouge in Louisiana
alleging substantially the same matters. The Company anticipates a trial, in state court, to begin in 2023. 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.
Note 24 — 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 operations.
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.
California Station Power — As the result of unfavorable final and non-appealable litigation, the Company accrued a
liability associated with consumption of station power at the Company's Encina power plant facility in California after August
30, 2010. The Company has established an appropriate accrual pending potential regulatory action by San Diego Gas & Electric
regarding the Company's Encina facility.
South Central — On August 4, 2016, NRG received a document hold notice from FERC regarding conduct in the MISO
and PJM markets. FERC Office of Enforcement Staff investigated potential violations of MISO rules involving bidding for the
Big Cajun 2 facility, as well as other aspects of NRG’s operations in MISO. On August 18, 2020, FERC Office of Enforcement
presented NRG with its preliminary findings. NRG responded to the preliminary findings on January 15, 2021. On September
16, 2021, FERC Office of Enforcement Staff informed NRG that the investigation is closed with no further action.
156
Note 25 — Environmental Matters
NRG is subject to a wide range of environmental laws in the development, construction, ownership and operation of
power plants. These laws generally require that governmental permits and approvals be obtained before construction and
maintained during operation of power plants. The electric generation industry has been facing increasingly stringent
requirements regarding air quality, GHG emissions, combustion byproducts, water discharge and use, and threatened and
endangered species. In general, future laws are expected to require the addition of emissions controls or other environmental
controls or to impose additional 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. The Company has elected to use a
$1 million disclosure threshold, as permitted, for environmental proceedings to which the government is a party.
Air
On July 8, 2019, the EPA promulgated the ACE rule, which rescinded the CPP, which had sought to broadly regulate CO2
emissions from the power sector. The ACE rule required states that have coal-fired EGUs to develop plans to seek heat rate
improvements from coal-fired EGUs. On January 19, 2021, the D.C. Circuit vacated the ACE rule (but on February 22, 2021, at
the EPA's request, stayed the issuance of the portion of the mandate that would vacate the repeal of the CPP). On October 29,
2021, the U.S. Supreme Court agreed to review the D.C. Circuit's decision, which should provide some clarity regarding the
scope of the EPA's authority to regulate CO2 under the Clean Air Act. The Company expects the EPA to promulgate a new rule
to regulate GHG emissions from power plants after a decision from the U.S. Supreme Court.
Water
Effluent Limitations Guidelines — In November 2015, the EPA revised the ELG for Steam Electric Generating Facilities,
which imposed more stringent requirements (as individual permits were renewed) for wastewater streams from FGD, fly ash,
bottom ash, and flue gas mercury control. On September 18, 2017, the EPA promulgated a final rule that, among other things,
postponed 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 amended the rule. On October 13, 2020, the EPA amended the 2015 ELG rule by: (i) altering the
stringency of certain limits for FGD wastewater; (ii) relaxing the zero-discharge requirement for bottom ash transport water;
and (iii) changing several deadlines. On July 26, 2021, the EPA announced that it is initiating a new rulemaking to evaluate
revising the ELG rule. While the EPA is developing the new rule, the existing rule (as amended in 2020) will stay in place, and
the EPA expects permitting authorities to continue to implement the current regulation. The EPA anticipates releasing a
proposed rule in fall 2022. In October 2021, NRG informed its regulators that the Company intends to comply with the ELG by
ceasing combustion of coal by the end of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by
the end of 2025 at its two plants in Texas.
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
amended 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.
In 2019 and 2020, the EPA proposed several changes to this rule. On August 28, 2020, the EPA finalized "A Holistic Approach
to Close Part A: Deadline to Initiate Closure," which amended the April 2015 Rule to address the August 2018 D.C. Circuit
decision and extend some of the deadlines. On November 12, 2020, the EPA finalized "A Holistic Approach to Closure Part B,"
which further amended the April 2015 Rule to, among other things, provide procedures for requesting approval to operate
existing impoundments with an alternative liner.
Note 26 — Cash Flow Information
Detail of supplemental disclosures of cash flow and non-cash investing and financing information was:
(In millions)
Year Ended December 31,
2021
2020
2019
Interest paid, net of amount capitalized . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
433 $
340 $
372
Income taxes paid, net of refunds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
32
24
Non-cash investing activities:
(Decreases)/additions to fixed assets for accrued capital expenditures . . . . . . .
(16)
(6)
8
1
157
Note 27 — Guarantees
NRG and its subsidiaries enter into various contracts that include indemnification and guarantee provisions as a routine
part of the Company's business activities. Examples of these contracts include asset purchases and sale agreements, commodity
sale and purchase agreements, retail contracts, joint venture agreements, EPC agreements, operation and maintenance
agreements, service agreements, settlement agreements, and other types of contractual agreements with vendors and other third
parties, as well as affiliates. These contracts generally indemnify the counterparty for tax, environmental liability, litigation and
other matters, as well as breaches of representations, warranties and covenants set forth in these agreements. The Company is
obligated with respect to customer deposits associated with the Company's retail operations. 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:
(In millions)
By Remaining Maturity at December 31,
2021
Guarantees
Letters of credit and surety bonds . . . . . . . . . . $
Asset sales guarantee obligations . . . . . . . . . .
Other guarantees . . . . . . . . . . . . . . . . . . . . . . .
Total guarantees . . . . . . . . . . . . . . . . . . . . . . . . $
Under
1 Year
1-3 Years
3-5 Years
Over
5 Years
Total
2020 Total
4,064 $
269
—
4,333 $
31 $
25
—
56 $
— $
24
—
24 $
— $
96
93
189 $
4,095 $
414
93
4,602 $
1,153
506
87
1,746
Letters of credit and surety bonds — As of December 31, 2021, NRG and its consolidated subsidiaries were contingently
obligated for a total of $4.1 billion under letters of credit and surety bonds. The significant increase in 2021 is primarily due to
the acquisition of Direct Energy. 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
included in the table above, except for the California property tax indemnity for estimated increases in California property taxes
of certain solar properties that the Company agreed to indemnify NRG Yield for, as part of the agreement to sell NRG Yield
and the Renewables Platform. The California property tax indemnity is estimated to be $158 million as of December 31, 2021
and is included in the above table under asset sales guarantee obligations.
Other guarantees — NRG has issued other guarantees of obligations including payments under certain agreements with
respect to certain of its unconsolidated subsidiaries, payment or performance by fuel providers and payment or reimbursement
of credit support and deposits. The Company does not believe that it will be required to perform under these guarantees.
Other indemnities — Other indemnifications NRG has provided cover operational, tax, litigation and breaches of
representations, warranties and covenants. NRG has also indemnified, on a routine basis in the ordinary course of business,
consultants or other vendors who have provided services to the Company. NRG's maximum potential exposure under these
indemnifications can range from a specified dollar amount to an indeterminate amount, depending on the nature of the
transaction. Total maximum potential exposure under these indemnifications is not estimable due to uncertainty as to whether
claims will be made or how they will be resolved. NRG does not have any reason to believe that the Company will be required
to make any material payments under these indemnity provisions.
Because many of the guarantees and indemnities NRG issues to third parties and affiliates do not limit the amount or
duration of its obligations to perform under them, there exists a risk that the Company may have obligations in excess of the
amounts described above. For those guarantees and indemnities that do not limit the Company's liability exposure, it may not be
able to estimate what the Company's liability would be, until a claim is made for payment or performance, due to the contingent
nature of these contracts.
158
Note 28 — 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:
(In millions unless otherwise stated)
As of December 31, 2021
Ownership
Interest
Property, Plant &
Equipment
Accumulated
Depreciation
Construction in
Progress
South Texas Project Units 1 and 2, Bay City, TX . . .
Cedar Bayou Unit 4, Baytown, TX . . . . . . . . . . . . . .
44.00 % $
50.00 %
421 $
220
(208) $
(109)
4
12
SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2021, 2020 and 2019
(In millions)
Allowance for credit losses, deducted from
accounts receivable
Balance at
Beginning of
Period
Charged to
Costs and
Expenses
Charged to
Other Accounts
Deductions
Balance at
End of Period
Year Ended December 31, 2021 . . . . . . . . . . . . . . . . $
67 $
698 $
112 $
Year Ended December 31, 2020 . . . . . . . . . . . . . . . .
Year Ended December 31, 2019 . . . . . . . . . . . . . . . .
Income tax valuation allowance, deducted from
deferred tax assets
43
32
108
95
—
—
Year Ended December 31, 2021 . . . . . . . . . . . . . . . . $
266 $
(29) $
11 $
Year Ended December 31, 2020 . . . . . . . . . . . . . . . .
Year Ended December 31, 2019 . . . . . . . . . . . . . . . .
242
3,794
24
(3,543)
—
(9)
(194) (a) $
(84) (a)
(84) (a)
$
—
—
—
683
67
43
248
266
242
(a) Represents principally net amounts charged as uncollectible
159
Number
Description
EXHIBIT INDEX
Method of Filing
2.1
2.2
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.
2.3 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.
2.4 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.
2.5 Third Amended Joint Plan of Reorganization of GenOn Energy, Inc.
and its Debtor Affiliates.
Incorporated herein by reference to Exhibit 2.1 to the
Registrant's current report on Form 8-K filed on
December 18, 2017.
2.6†^
2.7^
2.8‡
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.
Purchase and Sale Agreement dated as of February 28, 2021
by and between NRG Energy, Inc., and Generation Bridge
Acquisition, LLC, as a Purchaser
Incorporated herein by reference to Exhibit 2.1 to the
Registrant's quarterly report on Form 10-Q filed on
May 6, 2021.
3.1 Amended and Restated Certificate of Incorporation.
3.2
Certificate of Amendment to Amended and Restated Certificate of
Incorporation.
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.
3.3
Fifth Amended and Restated By-Laws.
Filed herewith.
4.1
Specimen of Certificate representing common stock of NRG
Energy, Inc.
Incorporated herein by reference to Exhibit 4.3 to the
Registrant's quarterly report on Form 10-Q filed on
August 4, 2006.
4.2
4.3
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.
4.4
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.
Incorporated herein by reference to Exhibit 4.4 to the
Registrant's Current Report on Form 8-K, filed on
August 3, 2016.
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.
4.5
4.6
Fourth 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.
4.7
Form of 5.75% Senior Notes due 2028
4.8
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.
4.9
Indenture, dated May 24, 2018, among NRG Energy, Inc., the
guarantors named therein and Delaware Trust Company, as trustee.
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.
160
4.10
Form of 2.75% Convertible Senior Notes due 2048.
4.11 Description of NRG Energy, Inc. securities registered pursuant to
section 12 of the Securities Exchange Act of 1934
Incorporated herein by reference to Exhibit 4.2 to the
Registrant's Current Report on Form 8-K, filed on
May 25, 2018.
Incorporated herein by reference to Exhibit 4.15 to
the Registrant's Annual Report on Form 10-K, filed on
February 27, 2020.
4.12
4.13
Indenture, dated December 2, 2020, between NRG Energy, Inc. and
Deutsche Bank Trust Company Americas, as trustee, pertaining to
the Secured Notes.
Incorporated herein by reference to Exhibit 4.1 to the
Registrant's Current Report on Form 8-K, filed on
December 4, 2020.
Supplemental Indenture, dated December 2, 2020, among NRG
Energy, Inc., the guarantors named therein and Deutsche Bank Trust
Company Americas, as trustee, pertaining to the Secured Notes
Incorporated herein by reference to Exhibit 4.2 to the
Registrant's Current Report on Form 8-K, filed on
December 4, 2020.
4.14
Form of 2.000% Senior Secured First Lien Notes due 2025
4.15
Form of 2.450% Senior Secured First Lien Notes due 2027
Incorporated herein by reference to Exhibit 4.3 to the
Registrant's Current Report on Form 8-K, filed on
December 4, 2020.
Incorporated herein by reference to Exhibit 4.4 to the
Registrant's Current Report on Form 8-K, filed on
December 4, 2020.
4.16
4.17
Indenture, dated December 2, 2020, between NRG Energy, Inc. and
Deutsche Bank Trust Company Americas, as trustee, pertaining to
the Unsecured Notes
Incorporated herein by reference to Exhibit 4.5 to the
Registrant's Current Report on Form 8-K, filed on
December 4, 2020.
Supplemental Indenture, dated December 2, 2020, among NRG
Energy, Inc., the guarantors named therein and Deutsche Bank Trust
Company Americas, as trustee, pertaining to the Unsecured Notes
Incorporated herein by reference to Exhibit 4.6 to the
Registrant's Current Report on Form 8-K, filed on
December 4, 2020.
4.18
Form of 3.375% Senior Notes due 2029 (incorporated by reference
to Exhibit 4.6 filed herewith)
4.19
Form of 3.625% Senior Notes due 2031 (incorporated by reference
to Exhibit 4.6 filed herewith)
Incorporated herein by reference to Exhibit 4.7 to the
Registrant's Current Report on Form 8-K, filed on
December 4, 2020.
Incorporated herein by reference to Exhibit 4.8 to the
Registrant's Current Report on Form 8-K, filed on
December 4, 2020.
4.20
Facility Agreement, dated December 2, 2020, among NRG Energy,
Inc., the guarantors party thereto, Alexander Funding Trust and
Deutsche Bank Trust Company Americas, as the notes trustee
Incorporated herein by reference to Exhibit 4.9 to the
Registrant's Current Report on Form 8-K, filed on
December 4, 2020.
4.21 Letter of Credit Facility Agreement, dated December 2, 2020,
among NRG Energy, Inc., the financial institutions from time to
time party thereto as letter of credit issuers, and Deutsche Bank
Trust Company Americas, as administrative agent and as collateral
agent
4.22 Amended and Restated Declaration of Trust of Alexander Funding
Trust, dated December 2, 2020, among NRG Energy, Inc. as
depositor and in its own capacity, Deutsche Bank Trust Company
Americas, as trustee, and Deutsche Bank Trust Company Delaware,
as Delaware trustee
Incorporated herein by reference to Exhibit 4.10 to the
Registrant's Current Report on Form 8-K, filed on
December 4, 2020.
Incorporated herein by reference to Exhibit 4.11 to the
Registrant's Current Report on Form 8-K, filed on
December 4, 2020.
Indenture, dated December 2, 2020, between NRG Energy, Inc. and
Deutsche Bank Trust Company Americas, as trustee, pertaining to
the P-Caps Secured Notes
Incorporated herein by reference to Exhibit 4.12 to the
Registrant's Current Report on Form 8-K, filed on
December 4, 2020.
4.23
4.24
4.25
Supplemental Indenture, dated December 2, 2020, among NRG
Energy, Inc., the guarantors named therein and Deutsche Bank Trust
Company Americas, as trustee, pertaining to the P-Caps Secured
Notes
Form of 1.841% Senior Secured First Lien Notes due
2023(incorporated by reference to Exhibit 4.31 filed herewith)
4.26 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.
4.27
4.28
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.
161
Incorporated herein by reference to Exhibit 4.13 to the
Registrant's Current Report on Form 8-K, filed on
December 4, 2020.
Incorporated herein by reference to Exhibit 4.14 to the
Registrant's Current Report on Form 8-K, filed on
December 4, 2020.
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.
4.29
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.
4.30 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.
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.
4.31
4.32
Indenture, dated May 23, 2016, between NRG Energy, Inc. and
Delaware Trust Company (as successor in interest to Law Debenture
Trust Company of New York), as trustee.
Incorporated herein by reference to Exhibit 4.1 to the
Registrant's Current Report on Form 8-K filed on May
23, 2016.
Fifth Supplemental Indenture, dated May 14, 2019, 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 May
16, 2019.
4.33
Form of 5.250% Senior Notes due 2029.
4.34
Indenture, dated May 28, 2019, between NRG Energy, Inc. 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 May
14, 2019.
Incorporated herein by reference to Exhibit 4.1 to the
Registrant's Current Report on Form 8-K filed on May
30, 2019.
4.35
Supplemental Indenture, dated May 28, 2019, 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 May
30, 2019.
4.36
Form of 3.750% Senior Secured First Lien Notes due 2024
4.37
Form of 4.450% Senior Secured First Lien Notes due 2029
4.38
4.39
Fourth Amendment dated as of May 28, 2019 to the Second
Amended and Restated Credit Agreement dated as of June 30, 2016,
included as Annex A thereto a clean, conformed copy of the Second
Amended and Restated Credit Agreement
Fifth Amendment to Credit Agreement and Third Amendment to
Collateral Trust Agreement, dated as of August 20, 2020, by and
among NRG Energy, Inc., its subsidiaries parties thereto, the lenders
party thereto, Citicorp North America, Inc., as administrative agent
and collateral agent, and Deutsche Bank Trust Company Americas,
as collateral trustee.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant's Current Report on Form 8-K filed on May
30, 2019.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant's Current Report on Form 8-K filed on May
30, 2019.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's Current Report on Form 8-K filed on
November 7, 2019.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant's Current Report on Form 8-K filed on
August 21, 2020.
4.40 Receivables Sale Agreement, dated as of September 22, 2020,
among the Originators from time to time parties thereto, NRG Retail
LLC, as Servicer, and NRG Receivables LLC.
Incorporated herein by reference to Exhibit 10.1 to the
Registrant’s Current Report on Form 8-K filed on
September 22, 2020.
4.41 Receivables Loan and Servicing Agreement, dated as of September
22, 2020, among NRG Receivables LLC, as Borrower, NRG Retail
LLC, as Servicer, the persons from time to time party thereto as
Conduit Lenders, the persons from time to time party thereto as
Committed Lenders, the persons from time to time party thereto as
Facility Agents, the financial institutions from time to time party
thereto as LC Issuers, and Royal Bank of Canada as Administrative
Agent
4.42
Supplemental Indenture (Additional Subsidiary Guarantees-2.750%
Convertible Senior Notes due 2048) dated January 5, 2021, among
NRG Energy, Inc., each of its guarantor subsidiaries, and Delaware
Trust Company as trustee.
4.43 Supplemental Indenture (Additional Subsidiary Guarantees
1.841% Senior Secured First Lien Notes due 2023) dated
January 5, 2021, among NRG Energy, Inc., each of its
guarantor subsidiaries, and Deutsche Bank Trust Company
Americas as trustee.
Incorporated herein by reference to Exhibit 10.2 to the
Registrant’s Current Report on Form 8-K filed on
September 22, 2020.
Incorporated herein by reference to Exhibit 4.1 to the
Registrant's quarterly report on Form 10-Q filed on
May 6, 2021.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant's quarterly report on Form 10-Q filed on
May 6, 2021.
162
4.44
4.45
4.46
4.47
4.48
4.49
4.50
4.51
4.52
Supplemental Indenture (additional Subsidiary Guarantees-6.625%
Senior Notes due 2027) dated January 5, 2021, among NRG Energy,
Inc., each of its guarantor subsidiaries , and Delaware Trust
Company as trustee.
Supplemental Indenture (additional Subsidiary Guarantees-5.750%
Senior Notes due 2028) dated January 5, 2021, Supplemental
Indenture (additional Subsidiary Guarantees-5.750% Senior Notes
due 2028) dated January 5, 2021, among NRG Energy, Inc., each of
its guarantor subsidiaries, and Delaware Trust Company as trustee.
Supplemental Indenture (additional Subsidiary Guarantees-5.250%
Senior Notes due 2029) dated January 5, 2021, among NRG Energy,
Inc., each of its guarantor subsidiaries, and Delaware Trust
Company as trustee.
Supplemental Indenture (Additional Subsidiary Guarantees 3.375%
Senior Notes due 2029 and 3.625% Senior Notes due 2031) dated
January 5, 2021, among NRG Energy, Inc., each of its guarantor
subsidiaries , and Deutsche Bank Trust Company Americas as
trustee.
Supplemental Indenture (additional Subsidiary Guarantees-3.750%
Senior Secured First Lien Notes due 2024 and 4.450% Senior
Secured First Lien Notes due 2029) dated January 5, 2021, among
NRG Energy, Inc., each of its guarantor subsidiaries , and Delaware
Trust Company as trustee.
Supplemental Indenture (Additional Subsidiary Guarantees 2.000%
Senior Secured First Lien Notes due 2025 and 2.450% Senior
Secured First Lien Notes due 2027) dated January 5, 2021, among
NRG Energy, Inc., each of its guarantor subsidiaries , and Deutsche
Bank Trust Company Americas as trustee.
Second Supplemental Indenture, dated August 23, 2021, among
NRG Energy, Inc., the guarantors named therein and Deutsche Bank
Trust Company Americas, as trustee.
Form of 3.875% Senior Notes due 2032.
Incorporated herein by reference to Exhibit 4.4 to the
Registrant's quarterly report on Form 10-Q filed on
May 6, 2021.
Incorporated herein by reference to Exhibit 4.5 to the
Registrant's quarterly report on Form 10-Q filed on
May 6, 2021.
Incorporated herein by reference to Exhibit 4.6 to the
Registrant's quarterly report on Form 10-Q filed on
May 6, 2021.
Incorporated herein by reference to Exhibit 4.7 to the
Registrant's quarterly report on Form 10-Q filed on
May 6, 2021.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant's Current Report on Form 8-K, filed on
August 23, 2021.
Incorporated herein by reference to Exhibit 4.3 to the
Registrant's Current Report on Form 8-K, filed on
August 23, 2021.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant's Current Report on Form 8-K, filed on
August 23, 2021.
Incorporated herein by reference to Exhibit 4.2 to the
Registrant's Current Report on Form 8-K, filed on
August 23, 2021.
Supplemental Indenture (Settlement Elections - 2.750% Convertible
Senior Notes due 2048) dated February 22, 2022, among NRG
Energy, Inc., each of its guarantor subsidiaries, and Delaware Trust
Company as trustee.
Filed herewith.
4.53 Supplemental Indenture (Additional Subsidiary
Filed herewith.
Guarantees-2.750% Convertible Senior Notes due 2048)
dated February 17, 2022, among NRG Energy, Inc., each of
its guarantor subsidiaries, and Delaware Trust Company as
trustee.
4.54 Supplemental Indenture (Additional Subsidiary
Filed herewith.
Guarantees-1.841% Senior Secured First Lien Notes due
2023) dated February 17, 2022, among NRG Energy, Inc.,
each of its guarantor subsidiaries, and Deutsche Bank Trust
Company Americas as trustee.
4.55 Supplemental Indenture (Additional Subsidiary
Filed herewith.
Guarantees-6.625% Senior Notes due 2027) dated February
17, 2022, among NRG Energy, Inc., each of its guarantor
subsidiaries, and Delaware Trust Company as trustee.
4.56 Supplemental Indenture (Additional Subsidiary
Filed herewith.
Guarantees-5.750% Senior Notes due 2028) dated February
17, 2022, among NRG Energy, Inc., each of its guarantor
subsidiaries, and Delaware Trust Company as trustee.
4.57 Supplemental Indenture (Additional Subsidiary
Filed herewith.
Guarantees-5.250% Senior Notes due 2029) dated February
17, 2022, among NRG Energy, Inc., each of its guarantor
subsidiaries, and Delaware Trust Company as trustee.
163
4.58 Supplemental Indenture (Additional Subsidiary
Filed herewith.
Guarantees-3.375% Senior Notes due 2029 and 3.625%
Senior Notes due 2031) dated February 17, 2022, among
NRG Energy, Inc., each of its guarantor subsidiaries, and
Deutsche Bank Trust Company Americas as trustee.
4.59 Supplemental Indenture (Additional Subsidiary
Filed herewith.
Guarantees-3.750% Senior Secured First Lien Notes due
2024 and 4.450% Senior Secured First Lien Notes due 2029)
dated February 17, 2022, among NRG Energy, Inc., each of
its guarantor subsidiaries, and Delaware Trust Company as
trustee.
4.60 Supplemental Indenture (Additional Subsidiary
Filed herewith.
Guarantees-2.000% Senior Secured First Lien Notes due
2025 and 2.450% Senior Secured First Lien Notes due 2027)
dated February 17, 2022, among NRG Energy, Inc., each of
its guarantor subsidiaries, and Deutsche Bank Trust
Company Americas as trustee.
4.61 Supplemental Indenture (Additional Subsidiary
Filed herewith.
Guarantees-3.875% Senior Notes due 2032) dated February
17, 2022, among NRG Energy, Inc., each of its guarantor
subsidiaries, and Deutsche Bank Trust Company Americas as
trustee.
Form of NRG Energy, Inc. Long-Term Incentive Plan Deferred
Stock Unit Agreement for Directors.
10.1*
10.2*
Form of NRG Energy, Inc. Long-Term Incentive Plan Restricted
Stock Unit Agreement for Officers.
10.3*
Form of NRG Energy, Inc. Long-Term Incentive Plan Restricted
Stock Unit Agreement for Non-Officers.
10.4*
Form of NRG Energy, Inc. Long-Term Incentive Plan Performance
Stock Unit Agreement.
10.5*
Second Amended and Restated Annual Incentive Plan for
Designated Corporate Officers.
10.6† LLC Membership Interest Purchase Agreement between Reliant
Energy, Inc. and NRG Retail LLC, dated as of February 28, 2009.
10.7* The NRG Energy, Inc. Amended and Restated Long-Term Incentive
Plan.
10.8* NRG 2010 Stock Plan for GenOn Employees.
10.9* NRG Energy, Inc. Long-Term Incentive Plan Market Stock Unit
Agreement.
10.10* NRG Energy, Inc. 2010 Stock Plan For GenOn Employees Market
Stock Unit Agreement
10.11 Employment Agreement, dated December 21, 2015, by and between
NRG Energy, Inc. and Mauricio Gutierrez.
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 10.6 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 10.49 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 10.1 to the
Registrant's current report on Form 8-K filed on
December 24, 2015.
10.12
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.
10.13
Pension Indemnity Agreement, dated as of December 14, 2017, by
and between NRG Energy, Inc. and GenOn Energy, Inc.
Incorporated herein by reference to Exhibit 10.4 to the
Registrant's Current Report on Form 8-K filed on
December 18, 2017.
164
10.14 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.
10.15*
Form of NRG Energy, Inc. Long-Term Incentive Plan Relative
Performance Stock Unit Agreement for Officers.
10.16*
Form of NRG Energy, Inc. Long-Term Incentive Plan Relative
Performance Stock Unit Agreement for Senior Vice Presidents.
10.17† 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).
10.18*
Amended and Restated Employee Stock Purchase Plan
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 Quarterly Report on Form 10-Q filed on
May 2, 2019.
10.19* 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 10.2 to the
Registrant's Quarterly Report on Form 10-Q filed on
August 2, 2018.
10.20 A copy of Amendment No. 1 to Receivables Loan and Servicing
Agreement, dated as of July 26, 2021, among NRG Retail LLC, as
Servicer, NRG Receivables LLC, as Borrower, NRG Energy, Inc.,
as Performance Guarantor, the Conduit Lenders, Committed
Lenders, Facility Agents and LC Issuers party, and Royal Bank of
Canada, as administrative Agent, and included as Exhibit A-2
thereto a clean, conformed copy of the Receivables Loan and
Servicing Agreement.
Form of NRG Energy, Inc. Long-Term Incentive Plan Relative
Performance Stock Unit Agreement for Chief Executive Officer
10.21*
Incorporated herein by reference to Exhibit 4.9 to the
Registrant's quarterly report on Form 10-Q filed on
August 5, 2021.
Filed herewith.
10.22*
Form of NRG Energy, Inc. Long-Term Incentive Plan Relative
Performance Stock Unit Agreement for Executive Vice Presidents
Filed herewith.
10.23*
Form of NRG Energy, Inc. Long-Term Incentive Plan Relative
Performance Stock Unit Agreement for Senior Vice Presidents.
21.1
22.1
23.1
31.1
31.2
31.3
Subsidiaries of NRG Energy, Inc.
List of Guarantor Subsidiaries
Consent of KPMG LLP.
Rule 13a-14(a)/15d-14(a) certification of Mauricio Gutierrez.
Rule 13a-14(a)/15d-14(a) certification of Alberto Fornaro.
Rule 13a-14(a)/15d-14(a) certification of Emily Picarello.
Filed herewith.
Filed herewith.
Filed herewith.
Filed herewith.
Filed herewith.
Filed herewith.
Filed herewith.
32
Section 1350 Certification.
101 INS
Inline XBRL Instance Document.
101 SCH
Inline XBRL Taxonomy Extension Schema.
101 CAL
Inline XBRL Taxonomy Extension Calculation Linkbase.
101 DEF
Inline XBRL Taxonomy Extension Definition Linkbase.
101 LAB
Inline XBRL Taxonomy Extension Label Linkbase.
101 PRE
Inline XBRL Taxonomy Extension Presentation Linkbase.
104
Cover Page Interactive Data File (the cover page interactive data file
does not appear in Exhibit 104 because it's Inline XBRL tags are
embedded within the Inline XBRL document).
Furnished herewith.
The instance document does not appear in the
interactive data file because its XBRL tags are
embedded within the inline XBRL document.
Filed herewith.
Filed herewith.
Filed herewith.
Filed herewith.
Filed herewith.
Filed herewith.
165
*
†
^
‡
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.
Portions of this exhibit have been excluded because they are both not material and would likely cause competitive harm to the
registrant if publicly disclosed. Information that has been omitted has been noted in this document with a placeholder identified by
the mark “[***]”.
Item 16. Form 10-K Summary
None.
166
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 24, 2022
167
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 24, 2022.
Signature
/s/ MAURICIO GUTIERREZ
Mauricio Gutierrez
/s/ ALBERTO FORNARO
Alberto Fornaro
/s/ EMILY PICARELLO
Emily Picarello
/s/ LAWRENCE S. COBEN
Lawrence S. Coben
/s/ E. SPENCER ABRAHAM
E. Spencer Abraham
/s/ ANTONIO CARRILLO
Antonio Carrillo
/s/ MATTHEW CARTER, JR.
Matthew Carter, Jr.
/s/ HEATHER COX
Heather Cox
/s/ ELISABETH B. DONOHUE
Elisabeth B. Donohue
/s/ PAUL W. HOBBY
Paul W. Hobby
/s/ ALEXANDRA PRUNER
Alexandra Pruner
/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)
Corporate Controller
(Principal Accounting Officer)
Date
February 24, 2022
February 24, 2022
February 24, 2022
Chair of the Board
February 24, 2022
February 24, 2022
February 24, 2022
February 24, 2022
February 24, 2022
February 24, 2022
February 24, 2022
February 24, 2022
February 24, 2022
February 24, 2022
Director
Director
Director
Director
Director
Director
Director
Director
Director
168