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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q

☒ |  | Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
|  | For the Quarterly Period Ended: | March 31, 2021 |
☐ |  | Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission File Number: 001-15891
NRG Energy, Inc.
(Exact name of registrant as specified in its charter)

Delaware |  | 41-1724239
(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)

910 Louisiana Street | Houston | Texas | 77002
(Address of principal executive offices) | (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 | Trading Symbol(s) | Name of Exchange on Which Registered
Common Stock, par value $0.01 | NRG | New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required 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 an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer | ☒ |  | Accelerated filer | ☐ |  | Non-accelerated filer | ☐ |  | Smaller reporting company | ☐ | Emerging growth company | ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ☐ No ☒
As of May 6, 2021, there were 244,753,963 shares of common stock outstanding, par value $0.01 per share.

1

TABLE OF CONTENTS
Index

CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION | 3
GLOSSARY OF TERMS | 5
PART I — FINANCIAL INFORMATION | 8
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES | 8
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 36
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 62
ITEM 4 — CONTROLS AND PROCEDURES | 64
PART II — OTHER INFORMATION | 65
ITEM 1 — LEGAL PROCEEDINGS | 65
ITEM 1A — RISK FACTORS | 65
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS | 65
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES | 65
ITEM 4 — MINE SAFETY DISCLOSURES | 65
ITEM 5 — OTHER INFORMATION | 65
ITEM 6 — EXHIBITS | 66
SIGNATURES | 67

2

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q 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 the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the 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 Risk Factors, in Part I, Item 1A of the Company's Annual Report on Form 10-K for the year ended December 31, 2020 and the following:
•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;
•Business uncertainties related to the acquisition of Direct Energy and NRG's ability to integrate 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;
•NRG's ability to successfully integrate, realize cost savings and manage any acquired businesses;
•NRG's ability to engage in successful sales and divestitures, as well as mergers and acquisitions activity;
•The effectiveness of NRG's risk management policies and procedures and the ability of NRG's counterparties to satisfy their financial commitments;
•Counterparties' collateral demands and other factors affecting NRG's liquidity position and financial condition;
•NRG's ability to operate its businesses efficiently and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;
•NRG's ability to enter into contracts to sell power or gas and procure fuel on acceptable terms and prices;
•The liquidity and competitiveness of wholesale markets for energy commodities;
•Government regulation, including changes in market rules, rates, tariffs and environmental laws;
•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 for units subject to capacity performance requirements in PJM, performance incentives in ISO-NE, and scarcity pricing in ERCOT;
•NRG's ability to borrow funds and access capital markets, as well as NRG's substantial indebtedness and the possibility that NRG may incur additional indebtedness 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;
•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;
•NRG's ability 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;
3

•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 factors that could cause NRG's actual results to differ materially from those contemplated in any forward-looking statements included in this Quarterly Report on Form 10-Q should not be construed as exhaustive.
4

GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:

2020 Form 10-K |  | NRG’s Annual Report on Form 10-K for the year ended December 31, 2020
ACE |  | Affordable Clean Energy
AESO |  | Alberta Electric System Operator
Agua Caliente |  | Agua Caliente Solar Project, a 290 MW photovoltaic power station located in Yuma County, Arizona in which NRG owned 35% interest
ARO |  | Asset Retirement Obligation
ASC |  | The FASB Accounting Standards Codification, which the FASB established as the source of authoritative GAAP
ASU |  | Accounting Standards Updates - updates to the ASC
Average realized power prices |  | Volume-weighted average power prices, net of average fuel costs and reflecting the impact of settled hedges
BTU |  | British Thermal Unit
Business |  | NRG Business, which serves medium and large business customers
CAA |  | Clean Air Act
CAISO |  | California Independent System Operator
CARES Act |  | Coronavirus Aid, Relief, and Economic Security Act of 2020
CCR |  | Coal Combustion Residuals
CDD |  | Cooling Degree Day
CFTC |  | U.S. Commodity Futures Trading Commission
Centrica |  | Centrica plc
CES |  | Clean Energy Standard
Cleco |  | Cleco Corporate Holdings LLC
CO 2 |  | Carbon Dioxide
ComEd |  | Commonwealth Edison
Company |  | NRG Energy, Inc.
Convertible Senior Notes |  | As of March 31, 2021, consists of NRG’s $575 million unsecured 2.75% Convertible Senior Notes due 2048
Cottonwood |  | Cottonwood Generating Station, a 1,153 MW natural gas-fueled plant
COVID-19 |  | Coronavirus Disease 2019
CPP |  | Clean Power Plan
CPUC |  | California Public Utilities Commission
CWA |  | Clean Water Act
D.C. Circuit |  | U.S. Court of Appeals for the District of Columbia Circuit
Economic gross margin |  | Sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales
EGU |  | Electric Generating Unit
EPA |  | U.S. Environmental Protection Agency
ERCOT |  | Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
ESPP |  | NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan
Exchange Act |  | The Securities Exchange Act of 1934, as amended
FASB |  | Financial Accounting Standards Board
FERC |  | Federal Energy Regulatory Commission
FGD |  | Flue gas desulfurization
FTRs |  | Financial Transmission Rights
GAAP |  | Generally accepted accounting principles in the U.S.
GHG |  | Greenhouse Gas
GW |  | Gigawatts

5

Green Mountain Energy |  | Green Mountain Energy Company
GWh |  | Gigawatt Hour
HDD |  | Heating Degree Day
Heat Rate |  | A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWhs generated. Heat rates can be expressed as either gross or net heat rates, depending upon whether the electricity output measured is gross or net generation. Heat rates are generally expressed as BTU per net kWh
Home |  | NRG Home, which serves Mass Market customers
HLW |  | High-level radioactive waste
ICE |  | Intercontinental Exchange
IESO |  | Independent Electricity System Operator
ISO |  | Independent System Operator, also referred to as RTOs
ISO-NE |  | ISO New England Inc.
Ivanpah |  | 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
kWh |  | Kilowatt-hour
LaGen |  | Louisiana Generating, LLC
LIBOR |  | London Inter-Bank Offered Rate
LTIPs |  | Collectively, the NRG long-term incentive plan ("LTIP") and the NRG GenOn LTIP
Mass Market |  | Residential and small commercial customers
MDth |  | Thousand Dekatherms
Midwest Generation |  | Midwest Generation, LLC
MISO |  | Midcontinent Independent System Operator, Inc.
MMBtu |  | Million British Thermal Units
MW |  | Megawatts
MWh |  | Saleable megawatt hour net of internal/parasitic load megawatt-hour
NAAQS |  | National Ambient Air Quality Standards
NEPOOL |  | New England Power Pool
NERC |  | North American Electric Reliability Corporation
Net Exposure |  | Counterparty credit exposure to NRG, net of collateral
Net Revenue Rate |  | Sum of retail revenues less TDSP transportation charges
Nodal |  | Nodal Exchange is a derivatives exchange
NOL |  | Net Operating Loss
NOx |  | Nitrogen Oxides
NPNS |  | Normal Purchase Normal Sale
NRC |  | U.S. Nuclear Regulatory Commission
NRG |  | NRG Energy, Inc.
Nuclear Decommissioning Trust Fund |  | NRG's nuclear decommissioning trust fund assets, which are for the Company's portion of the decommissioning of the STP, Units 1 & 2
Nuclear Waste Policy Act |  | U.S. Nuclear Waste Policy Act of 1982
NYISO |  | New York Independent System Operator
NYMEX |  | New York Mercantile Exchange
NYSPSC |  | New York State Public Service Commission
OCI/OCL |  | Other Comprehensive Income/(Loss)
Petra Nova |  | Petra Nova Parish Holdings, LLC
PJM |  | PJM Interconnection, LLC
PM2.5 |  | Particulate Matter that has a diameter of less than 2.5 micrometers
PPA |  | Power Purchase Agreement
PUCT |  | Public Utility Commission of Texas

6

RCE |  | Residential Customer Equivalent is a unit of measure used by the energy industry to denote the typical annual commodity consumption by a single-family residential customer. 1 RCE represents 1,000 therms of natural gas or 10,000 kWh of electricity
RCRA |  | Resource Conservation and Recovery Act of 1976
Receivables Securitization Facilities |  | Collectively, the Receivables Facility and the Repurchase Facility
Revolving Credit Facility |  | The Company's $3.7 billion revolving credit facility due 2024, was amended on May 28, 2019 and August 20, 2020
RGGI |  | Regional Greenhouse Gas Initiative
RTO |  | Regional Transmission Organization, also referred to as ISOs
SEC |  | U.S. Securities and Exchange Commission
Securities Act |  | The Securities Act of 1933, as amended
Senior Notes |  | As of March 31, 2021, NRG's $5.3 billion outstanding unsecured senior notes consisting of $1.0 billion of the 7.25% senior notes due 2026, $1.2 billion 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, and $1.0 billion of the 3.625% senior notes due 2031
Senior Secured First Lien Notes |  | As of March 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
Services |  | NRG Services, which primarily includes the services businesses acquired in the Direct Energy Acquisition
SNF |  | Spent Nuclear Fuel
SO 2 |  | Sulfur Dioxide
South Central Portfolio |  | 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
STP |  | South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
STPNOC |  | South Texas Project Nuclear Operating Company
TDSP |  | Transmission/distribution service provider
Texas Bankruptcy Court |  | United States Bankruptcy Court for the Southern District of Texas, Houston Division
U.S. |  | United States of America
U.S. DOE |  | U.S. Department of Energy
Utility Scale Solar |  | Solar power projects, typically 20 MW or greater in size (on an alternating current basis), that are interconnected into the transmission or distribution grid to sell power at a wholesale level
VaR |  | Value at Risk
VIE |  | Variable Interest Entity
Winter Storm Uri |  | A major winter and ice storm that had widespread impacts across North America occurring in February 2021

7

PART I — FINANCIAL INFORMATION
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

| Three months ended March 31, |  |
(In millions, except for per share amounts) | 2021 |  | 2020 |  |  |  |
Operating Revenues |  |  |  |  |  |  |
Total operating revenues | $ | 8,091 |  |  | $ | 2,019 |  |  |  |  |
Operating Costs and Expenses |  |  |  |  |  |  |
Cost of operations | 6,864 |  |  | 1,457 |  |  |  |  |
Depreciation and amortization | 317 |  |  | 109 |  |  |  |  |
Selling, general and administrative costs | 330 |  |  | 190 |  |  |  |  |
Provision for credit losses | 611 |  |  | 24 |  |  |  |  |
Acquisition-related transaction and integration costs | 42 |  |  | 1 |  |  |  |  |
Total operating costs and expenses | 8,164 |  |  | 1,781 |  |  |  |  |
Gain on sale of assets | 17 |  |  | 6 |  |  |  |  |
Operating (Loss)/Income | (56) |  |  | 244 |  |  |  |  |
Other (Expense)/Income |  |  |  |  |  |  |
Equity in losses of unconsolidated affiliates | (6) |  |  | (11) |  |  |  |  |
Impairment losses on investments | — |  |  | (18) |  |  |  |  |
Other income, net | 22 |  |  | 27 |  |  |  |  |
Interest expense | (127) |  |  | (98) |  |  |  |  |
Total other expense | (111) |  |  | (100) |  |  |  |  |
(Loss)/Income Before Income Taxes | (167) |  |  | 144 |  |  |  |  |
Income tax (benefit)/expense | (85) |  |  | 23 |  |  |  |  |
Net (Loss)/Income | (82) |  |  | 121 |  |  |  |  |
(Loss)/Income per Share |  |  |  |  |  |  |
Weighted average number of common shares outstanding — basic | 245 |  |  | 248 |  |  |  |  |
(Loss)/Income per Weighted Average Common Share — Basic | $ | (0.33) |  |  | $ | 0.49 |  |  |  |  |
Weighted average number of common shares outstanding — diluted | 245 |  |  | 249 |  |  |  |  |
(Loss)/Income per Weighted Average Common Share — Diluted | $ | (0.33) |  |  | $ | 0.49 |  |  |  |  |

See accompanying notes to condensed consolidated financial statements.
8

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME
(Unaudited)

| Three months ended March 31, |  |
(In millions) | 2021 |  | 2020 |  |  |  |
Net (Loss)/Income | $ | (82) |  |  | $ | 121 |  |  |  |  |
Other Comprehensive Income/(Loss) |  |  |  |  |  |  |
Foreign currency translation adjustments | 3 |  |  | (15) |  |  |  |  |
Other comprehensive income/(loss) | 3 |  |  | (15) |  |  |  |  |
Comprehensive (Loss)/Income | $ | (79) |  |  | $ | 106 |  |  |  |  |

See accompanying notes to condensed consolidated financial statements.
9

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS

| March 31, 2021 |  | December 31, 2020
(In millions, except share data) | (Unaudited) |  | (Audited)
ASSETS |  |  |
Current Assets |  |  |
Cash and cash equivalents | $ | 501 |  |  | $ | 3,905 |
Funds deposited by counterparties | 55 |  |  | 19 |
Restricted cash | 18 |  |  | 6 |
Accounts receivable, net | 3,037 |  |  | 904 |
Inventory | 316 |  |  | 327 |
Derivative instruments | 1,816 |  |  | 560 |
Cash collateral paid in support of energy risk management activities | 298 |  |  | 50 |
Prepayments and other current assets | 511 |  |  | 257 |
Total current assets | 6,552 |  |  | 6,028 |
Property, plant and equipment, net | 2,328 |  |  | 2,547 |
Other Assets |  |  |
Equity investments in affiliates | 162 |  |  | 346 |
Operating lease right-of-use assets, net | 312 |  |  | 301 |
Goodwill | 1,572 |  |  | 579 |
Intangible assets, net | 3,054 |  |  | 668 |
Nuclear decommissioning trust fund | 909 |  |  | 890 |
Derivative instruments | 1,008 |  |  | 261 |
Deferred income taxes | 2,719 |  |  | 3,066 |
Other non-current assets | 625 |  |  | 216 |
Total other assets | 10,361 |  |  | 6,327 |
Total Assets | $ | 19,241 |  |  | $ | 14,902 |
LIABILITIES AND STOCKHOLDERS' EQUITY |  |  |
Current Liabilities |  |  |
Current portion of long-term debt and finance leases | 831 |  |  | 1 |
Current portion of operating lease liabilities | 79 |  |  | 69 |
Accounts payable | 2,216 |  |  | 649 |
Derivative instruments | 1,606 |  |  | 499 |
Cash collateral received in support of energy risk management activities | 55 |  |  | 19 |
Accrued expenses and other current liabilities | 1,008 |  |  | 678 |
Total current liabilities | 5,795 |  |  | 1,915 |
Other Liabilities |  |  |
Long-term debt and finance lease | 8,705 |  |  | 8,691 |
Non-current operating lease liabilities | 280 |  |  | 278 |
Nuclear decommissioning reserve | 308 |  |  | 303 |
Nuclear decommissioning trust liability | 580 |  |  | 565 |
Derivative instruments | 834 |  |  | 385 |
Deferred income taxes | 30 |  |  | 19 |
Other non-current liabilities | 1,192 |  |  | 1,066 |
Total other liabilities | 11,929 |  |  | 11,307 |
Total Liabilities | 17,724 |  |  | 13,222 |
Commitments and Contingencies |  |  |
Stockholders' Equity |  |  |
Common stock; $0.01 par value; 500,000,000 shares authorized; 423,519,121 and 423,057,848 shares issued and 244,693,206 and 244,231,933 shares outstanding at March 31, 2021 and December 31, 2020, respectively | 4 |  |  | 4 |
Additional paid-in-capital | 8,513 |  |  | 8,517 |
Accumulated deficit | (1,565) |  |  | (1,403) |
Treasury stock, at cost - 178,825,915 shares at March 31, 2021 and December 31, 2020 | (5,232) |  |  | (5,232) |
Accumulated other comprehensive loss | (203) |  |  | (206) |
Total Stockholders' Equity | 1,517 |  |  | 1,680 |
Total Liabilities and Stockholders' Equity | $ | 19,241 |  |  | $ | 14,902 |

See accompanying notes to condensed consolidated financial statements.
10

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

| Three months ended March 31,
(In millions) | 2021 |  | 2020
Cash Flows from Operating Activities |  |  |
Net (Loss)/Income | $ | (82) |  |  | $ | 121 |
Adjustments to reconcile net (loss)/income to cash (used)/provided by operating activities: |  |  |
Distributions from and equity in losses of unconsolidated affiliates | 17 |  |  | 16 |
Depreciation and amortization | 317 |  |  | 109 |
Accretion of asset retirement obligations | 3 |  |  | 11 |
Provision for credit losses | 611 |  |  | 24 |
Amortization of nuclear fuel | 13 |  |  | 13 |
Amortization of financing costs and debt discounts | 11 |  |  | 6 |
Amortization of emissions allowances and energy credits | 7 |  |  | 7 |
Amortization of unearned equity compensation | 4 |  |  | 5 |
Gain on sale and disposal of assets | (18) |  |  | (14) |
Impairment losses | — |  |  | 18 |
Changes in derivative instruments | (902) |  |  | (46) |
Changes in deferred income taxes and liability for uncertain tax benefits | (71) |  |  | 19 |
Changes in collateral deposits in support of energy risk management activities | 1 |  |  | 9 |
Changes in nuclear decommissioning trust liability | 15 |  |  | 8 |
Changes in other working capital | (843) |  |  | (98) |
Cash (used)/provided by operating activities | (917) |  |  | 208 |
Cash Flows from Investing Activities |  |  |
Payments for acquisitions of businesses, net of cash acquired | (3,482) |  |  | — |
Capital expenditures | (63) |  |  | (66) |
Net purchases of emission allowances | (5) |  |  | (8) |
Investments in nuclear decommissioning trust fund securities | (129) |  |  | (121) |
Proceeds from the sale of nuclear decommissioning trust fund securities | 118 |  |  | 112 |
Proceeds from sale of assets, net of cash disposed | 197 |  |  | 15 |
Cash used by investing activities | (3,364) |  |  | (68) |
Cash Flows from Financing Activities |  |  |
Payments of dividends to common stockholders | (80) |  |  | (74) |
Payments for share repurchase activity | (9) |  |  | (179) |
Net payments from settlement of acquired derivatives that include financing elements | 190 |  |  | (3) |
Net proceeds of Revolving Credit Facility and Receivables Securitization Facilities | 825 |  |  | 552 |
Payments of debt issuance costs | (2) |  |  | — |
Proceeds from issuance of common stock | 1 |  |  | — |
Repayments of long-term debt and finance leases | (1) |  |  | (60) |
Proceeds from issuance of long-term debt | — |  |  | 59 |
Purchase of and distributions to noncontrolling interests from subsidiaries | — |  |  | (2) |
Cash provided by financing activities | 924 |  |  | 293 |
Effect of exchange rate changes on cash and cash equivalents | 1 |  |  | — |
Net (Decrease)/increase in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash | (3,356) |  |  | 433 |
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period | 3,930 |  |  | 385 |
Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period | $ | 574 |  |  | $ | 818 |

See accompanying notes to condensed consolidated financial statements.
11

NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(Unaudited)

(In millions) |  |  | Common Stock |  | Additional Paid-In Capital |  | Accumulated Deficit |  | Treasury Stock |  | Accumulated Other Comprehensive Loss |  |  |  | Total Stock-holders' Equity
Balance at December 31, 2020 |  |  | $ | 4 |  |  | $ | 8,517 |  |  | $ | (1,403) |  |  | $ | (5,232) |  |  | $ | (206) |  |  |  |  | $ | 1,680 |
Net loss |  |  |  |  |  |  | (82) |  |  |  |  |  |  |  |  | (82) |
Other comprehensive income |  |  |  |  |  |  |  |  |  |  | 3 |  |  |  |  | 3 |
Equity-based awards activity, net(a) |  |  |  |  | (5) |  |  |  |  |  |  |  |  |  |  | (5) |
Issuance of common stock |  |  |  |  | 1 |  |  |  |  |  |  |  |  |  |  | 1 |
Common stock dividends and dividend equivalents declared(b) |  |  |  |  |  |  | (80) |  |  |  |  |  |  |  |  | (80) |
Balance at March 31, 2021 |  |  | $ | 4 |  |  | $ | 8,513 |  |  | $ | (1,565) |  |  | $ | (5,232) |  |  | $ | (203) |  |  |  |  | $ | 1,517 |

(In millions) |  |  | Common Stock |  | Additional Paid-In Capital |  | Accumulated Deficit |  | Treasury Stock |  | Accumulated Other Comprehensive Loss |  |  |  | Total Stock-holders' Equity
Balance at December 31, 2019 |  |  | $ | 4 |  |  | $ | 8,501 |  |  | $ | (1,616) |  |  | $ | (5,039) |  |  | $ | (192) |  |  |  |  | $ | 1,658 |
Net income |  |  |  |  |  |  | 121 |  |  |  |  |  |  |  |  | 121 |
Other comprehensive loss |  |  |  |  |  |  |  |  |  |  | (15) |  |  |  |  | (15) |
Repurchase of partners' equity interest in VIE |  |  |  |  | 18 |  |  |  |  |  |  |  |  |  |  | 18 |
Share repurchases |  |  |  |  |  |  |  |  | (150) |  |  |  |  |  |  | (150) |
Equity-based awards activity, net(a) |  |  |  |  | (21) |  |  |  |  |  |  |  |  |  |  | (21) |
Common stock dividends and dividend equivalents declared(b) |  |  |  |  |  |  | (75) |  |  |  |  |  |  |  |  | (75) |
Balance at March 31, 2020 |  |  | $ | 4 |  |  | $ | 8,498 |  |  | $ | (1,570) |  |  | $ | (5,189) |  |  | $ | (207) |  |  |  |  | $ | 1,536 |

(a) Includes $(9) million and $(27) million of equivalent shares purchased in lieu of tax withholding on equity compensation issuances for the quarters ended March 31, 2021 and 2020, respectively
(b) Dividends per common share were $0.325 and $0.30 for the quarters ended March 31, 2021 and 2020, respectively
See accompanying notes to condensed consolidated financial statements.
12

NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 — Nature of Business and Basis of Presentation
General
NRG Energy, Inc., or NRG or the Company, is an integrated power company built on dynamic retail brands with diverse generation assets. NRG brings the power of energy to customers by producing and selling energy and related products and services, in major competitive power markets in the U.S. and Canada in a manner that delivers value to all of NRG's stakeholders. NRG is a customer-centric business focused on perfecting the integrated model by balancing retail load with generation supply within its deregulated markets. The Company sells energy, services, and innovative, sustainable products and services directly to retail customers under the names NRG, Reliant, Green Mountain Energy, Stream, and XOOM Energy, as well as other brand names owned by NRG, supported by approximately 23,000 MW of generation as of March 31, 2021.
NRG also conducts business under the brand name of Direct Energy as a result of the Company's acquisition of Direct Energy, a North American subsidiary of Centrica, on January 5, 2021. 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. In addition, Direct Energy is a participant in the wholesale gas and power markets in the United States and Canada. Refer to Note 4, Acquisitions and Dispositions, for further discussion of the acquisition of Direct Energy.
The acquired operations of Direct Energy are integrated into the existing NRG segment structure. Domestic customer and market operations will be combined into the corresponding geographical segments of Texas, East and West/Services/Other. The East segment will also include the deregulated customer and market operations of Canada. The West/Services/Other segment will also include activity related to the regulated operations in Alberta, Canada and the services businesses.
The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the SEC's regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the consolidated financial statements in the Company's 2020 Form 10-K. Interim results are not necessarily indicative of results for a full year.
In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company's consolidated financial position as of March 31, 2021, and the results of operations, comprehensive income, cash flows and statements of stockholders' equity for the three months ended March 31, 2021 and 2020.
Use of Estimates
The preparation of financial statements in conformity with GAAP 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.
Reclassifications
Certain prior year amounts have been reclassified for comparative purposes. The reclassifications did not affect consolidated results from operations, net assets or consolidated cash flows.
Note 2 — Summary of Significant Accounting Policies
Other Balance Sheet Information
The following table presents the accumulated depreciation included in property, plant and equipment, net and accumulated amortization included in intangible assets, net:

(In millions) | March 31, 2021 |  | December 31, 2020 |
Property, plant and equipment accumulated depreciation | $ | 1,566 |  |  | $ | 1,936 |  |
Intangible assets accumulated amortization | 1,424 |  |  | 1,357 |  |

13

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.
Retail trade receivables are reported on the balance sheet net of the allowance for credit losses. The Company accrues a provision 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 following table represents the activity in the allowance for credit losses for the three months ended March 31, 2021:

(In millions) | Three months ended March 31, 2021 |  |  |  | Three months ended March 31, 2020 |  |
Beginning balance | $ | 67 |  |  |  |  | $ | 43 |  |  |
Acquired balance from Direct Energy | 112 |  |  |  |  | — |  |  |
Provision for credit losses | 611 |  |  |  |  | 24 |  |  |
Write-offs | (48) |  |  |  |  | (32) |  |  |
Recoveries collected | 7 |  |  |  |  | 4 |  |  |
Ending balance | $ | 749 |  |  |  |  | $ | 39 |  |  |

The increase in the provision for credit losses during the three months ended March 31, 2021, compared to the same period in 2020 was primarily due to the impacts of Winter Storm Uri on bilateral finance hedging risk of $393 million, counterparty credit risk of $109 million and ERCOT default shortfall payments of $83 million, as well as the acquisition of Direct Energy.
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) | March 31, 2021 |  | December 31, 2020 |  |  |  |
Cash and cash equivalents | $ | 501 |  |  | $ | 3,905 |  |  |  |  |
Funds deposited by counterparties | 55 |  |  | 19 |  |  |  |  |
Restricted cash | 18 |  |  | 6 |  |  |  |  |
Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows | $ | 574 |  |  | $ | 3,930 |  |  |  |  |

Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties. Some amounts are segregated into separate accounts that are not contractually restricted but, based on the Company's intention, are not available for the payment of general corporate obligations. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's balance sheet, with an offsetting liability for this cash collateral received within current liabilities.
Restricted cash consists primarily of funds held within the Company's projects that are restricted for specific uses.
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 No. 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
14

approach. The adoption did not have a material impact on the Company's results of operations, cash flows, or statement of financial position.
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 No. 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, and interim periods within those fiscal years. Early adoption is permitted in fiscal years beginning after December 15, 2020, including interim periods within those fiscal years. The Company is currently in the process of assessing the impact of this guidance on the consolidated financial statements and disclosures related to earnings per share.
Note 3 — Revenue Recognition
Performance Obligations
As of March 31, 2021, estimated future fixed fee performance obligations are $544 million for the remaining nine months of fiscal year 2021, and $299 million, $51 million, $37 million and $20 million for the fiscal years 2022, 2023, 2024 and 2025, 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.
Disaggregated Revenues
The following tables represent the Company’s disaggregation of revenue from contracts with customers for the three months ended March 31, 2021 and 2020:

| Three months ended March 31, 2021
(In millions) | Texas |  | East |  | West/Services/Other |  | Corporate/Eliminations |  | Total
Retail revenue: |  |  |  |  |  |  |  |  |
Home(a) | $ | 1,542 |  |  | $ | 702 |  |  | $ | 474 |  |  | $ | — |  |  | $ | 2,718 |
Business | 572 |  |  | 2,841 |  |  | 31 |  |  | — |  |  | 3,444 |
Total retail revenue | 2,114 |  |  | 3,543 |  |  | 505 |  |  | — |  |  | 6,162 |
Energy revenue(c) | 285 |  |  | 126 |  |  | 70 |  |  | 1 |  |  | 482 |
Capacity revenue(c) | — |  |  | 141 |  |  | 14 |  |  | — |  |  | 155 |
Mark-to-market for economic hedging activities(d) | (1) |  |  | (4) |  |  | (28) |  |  | 1 |  |  | (32) |
Other revenue(b)(c) | 1,304 |  |  | 19 |  |  | 4 |  |  | (3) |  |  | 1,324 |
Total operating revenue | 3,702 |  |  | 3,825 |  |  | 565 |  |  | (1) |  |  | 8,091 |
Less: Lease revenue | — |  |  | — |  |  | 2 |  |  | — |  |  | 2 |
Less: Realized and unrealized ASC 815 revenue | 93 |  |  | 99 |  |  | (34) |  |  | 2 |  |  | 160 |
Total revenue from contracts with customers | $ | 3,609 |  |  | $ | 3,726 |  |  | $ | 597 |  |  | $ | (3) |  |  | $ | 7,929 |
(a) Home includes Services
(b) Other Revenue in Texas includes ancillary revenues of $1.2 billion driven by high pricing during Winter Storm Uri
(c) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions) | Texas |  | East |  | West/Services/Other |  | Corporate/Eliminations |  | Total
Energy revenue | $ | — |  |  | $ | 60 |  |  | $ | (4) |  |  | $ | 2 |  |  | $ | 58 |
Capacity revenue | — |  |  | 37 |  |  | — |  |  | — |  |  | 37 |
Other revenue | 94 |  |  | 6 |  |  | (2) |  |  | (1) |  |  | 97 |
(d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

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| Three months ended March 31, 2020
(In millions) | Texas |  | East |  | West/Services/Other |  | Corporate/Eliminations |  | Total
Retail revenue: |  |  |  |  |  |  |  |  |
Home(a) | $ | 1,032 |  |  | $ | 329 |  |  | $ | 18 |  |  | $ | (1) |  |  | $ | 1,378 |
Business | 260 |  |  | 23 |  |  | — |  |  | — |  |  | 283 |
Total retail revenue | 1,292 |  |  | 352 |  |  | 18 |  |  | (1) |  |  | 1,661 |
Energy revenue(b) | 5 |  |  | 45 |  |  | 75 |  |  | (1) |  |  | 124 |
Capacity revenue(b) | — |  |  | 134 |  |  | 15 |  |  | — |  |  | 149 |
Mark-to-market for economic hedging activities(c) | — |  |  | (20) |  |  | 15 |  |  | 1 |  |  | (4) |
Other revenue(b) | 61 |  |  | 10 |  |  | 20 |  |  | (2) |  |  | 89 |
Total operating revenue | 1,358 |  |  | 521 |  |  | 143 |  |  | (3) |  |  | 2,019 |
Less: Lease revenue | — |  |  | — |  |  | 5 |  |  | — |  |  | 5 |
Less: Realized and unrealized ASC 815 revenue | 7 |  |  | 39 |  |  | 44 |  |  | (1) |  |  | 89 |
Total revenue from contracts with customers | $ | 1,351 |  |  | $ | 482 |  |  | $ | 94 |  |  | $ | (2) |  |  | $ | 1,925 |
(a) Home includes Services
(b) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above:
(In millions) | Texas |  | East |  | West/Services/Other |  | Corporate/Eliminations |  | Total
Energy revenue | $ | — |  |  | $ | 35 |  |  | $ | 19 |  |  | $ | (1) |  |  | $ | 53 |
Capacity revenue | — |  |  | 24 |  |  | — |  |  | — |  |  | 24 |
Other revenue | 7 |  |  | — |  |  | 10 |  |  | (1) |  |  | 16 |
(c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815

Contract Balances
The following table reflects the contract assets and liabilities included in the Company’s balance sheet as of March 31, 2021 and December 31, 2020:

(In millions) | March 31, 2021 |  | December 31, 2020
Deferred customer acquisition costs | $ | 116 |  |  | $ | 113 |
Accounts receivable, net - Contracts with customers | 2,920 |  |  | 866 |
Accounts receivable, net - Derivative instruments | 113 |  |  | 33 |
Accounts receivable, net - Affiliate | 4 |  |  | 5 |
Total accounts receivable, net | $ | 3,037 |  |  | $ | 904 |
Unbilled revenues (included within Accounts receivable, net - Contracts with customers) | $ | 1,234 |  |  | $ | 393 |
Deferred revenues(a) | 258 |  |  | 60 |

(a) Deferred revenues from contracts with customers for the three months ended March 31, 2021 and the year ended December 31, 2020 were approximately $232 million and $31 million, respectively
The revenue recognized from contracts with customers during the three months ended March 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 three months ended March 31, 2021 and 2020 was primarily due to the timing difference of when consideration was received and when the performance obligation was transferred.
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Note 4 — Acquisitions 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, 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 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 and an initial 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 a reduction of $38 million. The Company expects to receive this payment from Centrica during the second quarter of 2021. The Company also increased its collective liquidity and 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:

| (In millions)
Available on Acquisition Closing Date |
Revolving Credit Facility commitment increase | $ | 802 |
Revolving Credit Facility new tranche | 273 |
Facility agreement in connection with the sale of pre-capitalized trust securities | 874 |
Available as of December 31, 2020 |
Credit default swap facility | 150 |
Revolving accounts receivable financing facility | 750 |
Repurchase facility | 75 |
Bilateral letter of credit facilities | 475 |
Total Increases to Liquidity and Collateral Facilities | $ | 3,399 |

For further discussion see Note 9, Long-term Debt and Finance Leases, and also Note 13, Receivables Securitization and Repurchase Facility, to the Company's 2020 Form 10-K.
Acquisition costs were $22 million for the three months ended March 31, 2021 and 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 provisionally recorded at their estimated fair values on the acquisition date. The initial accounting for the business combination is not complete because the evaluation necessary to assess the fair value of certain net assets acquired and the amount of goodwill to be recognized are still in process. The provisional amounts are subject to revision until the evaluations are completed to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date.
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The purchase price is provisionally allocated as follows:

| (In millions)
Current Assets |
Cash and cash equivalents | $ | 152 |
Funds deposited by counterparties | 21 |
Restricted cash | 9 |
Accounts receivable, net | 1,802 |
Inventory | 106 |
Derivative instruments | 1,014 |
Cash collateral paid in support of energy risk management activities | 233 |
Prepayments and other current assets | 181 |
Total current assets | 3,518 |
Property, plant and equipment, net | 178
Other Assets |
Goodwill(a)(b) | 990 |
Intangibles assets, net(b) | 2,559 |
Derivative instruments | 531
Other non-current assets | 31
Total other assets | 4,111 |
Total Assets | $ | 7,807 |
Current Liabilities |
Accounts payable | $ | 1,390 |
Derivative instruments | 1,266 |
Cash collateral received in support of energy risk management activities | 21 |
Accrued expenses and other current liabilities | 440 |
Total current liabilities | 3,117 |
Other Liabilities |
Derivative instruments | 562 |
Deferred income taxes | 433 |
Other non-current liabilities | 31 |
Total other liabilities | 1,026 |
Total Liabilities | $ | 4,143 |
Direct Energy Purchase Price | $ | 3,664 |

(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 expected to be deductible for tax purposes is $337 million.
(b) The allocation of goodwill and intangible assets to the Company's reportable segments is anticipated to be completed in the second quarter of 2021
The Company recorded revenue from Direct Energy of $4,161 million and income before income tax of $134 million during the three months ended March 31, 2021.
Pro forma comparative financial information for the Direct Energy acquisition has not been included for the three months ended March 31, 2021 and 2020, as the computation of such information is impracticable due to pre-acquisition financial statements for the reporting periods not being prepared in accordance with GAAP.
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Dispositions
On February 28, 2021, the Company entered into a definitive purchase agreement with Generation Bridge, an affiliate of ArcLight Capital Partners, to sell approximately 4,850 MW of fossil generating assets from its East and West regions of operations for total proceeds of $760 million, subject to standard purchase price adjustments and certain other indemnifications. As part of the transaction, NRG is entering into a tolling agreement for its 866 MW Arthur Kill plant in New York City through April 2025. The transaction is expected to close in the fourth quarter of 2021 and is subject to various closing conditions, approvals and consents, including FERC, NYSPSC, and antitrust review under the Hart-Scott-Rodino Act.
As of March 31, 2021, the following is classified as held for sale in the Consolidated Balance Sheet:

| (In millions)(a)
Current assets(b) | $ | 55 |
Property, plant and equipment, net | 385 |
Other non-current assets | 3 |
Total non-current assets(c) | 388 |
Total assets held for sale | $ | 443 |
Current liabilities(d) | 27 |
Non-current liabilities(e) | 60 |
Total liabilities held for sale | $ | 87 |

(a) Property, plant and equipment, net for the East and West/Services/Other segments was $237 million and $148 million, respectively. The remaining assets and liabilities were primarily in the East segment
(b) Included in prepayments and other current assets in the Consolidated Balance Sheet
(c) Included in other non-current assets in the Consolidated Balance Sheet
(d) Included in accrued expenses and other current liabilities in the Consolidated Balance Sheet
(e) Included in other non-current liabilities in the Consolidated Balance Sheet
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.
The Company completed other asset sales for cash proceeds of $2 million and $15 million during the three months ended March 31, 2021 and 2020, respectively.
Note 5 — Fair Value of Financial Instruments
For cash and cash equivalents, funds deposited by counterparties, restricted cash, accounts and other receivables, accounts payable, and cash collateral paid and received in support of energy risk management activities, the carrying amounts approximate fair values because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.
The estimated carrying amounts and fair values of NRG's recorded financial instruments not carried at fair market value are as follows:

| March 31, 2021 |  | December 31, 2020
(In millions) | Carrying Amount |  | Fair Value |  | Carrying Amount |  | Fair Value
Assets: |  |  |  |  |  |  |
Notes receivable | $ | 2 |  |  | $ | 2 |  |  | $ | 2 |  |  | $ | 2 |
Liabilities: |  |  |  |  |  |  |
Long-term debt, including current portion (a) | 9,609 |  |  | 10,007 |  |  | 8,781 |  |  | 9,446 |

(a) Excludes deferred financing costs, which are recorded as a reduction to long-term debt in the Company's consolidated balance sheets
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The fair value of the Company's publicly-traded long-term debt is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. The estimated fair value of the borrowing under the Revolving Credit Facility and Receivable Securitization Facilities approximates the carrying value because the interest rates vary with market interest rates, and is classified as Level 3 within the fair value hierarchy. The fair value of certain notes receivable of the Company is based on expected future cash flows discounted at market interest rate and is classified as Level 3 within the fair value hierarchy. The following table presents the level within the fair value hierarchy for long-term debt, including current portion, as of March 31, 2021 and December 31, 2020:

| March 31, 2021 |  | December 31, 2020
(In millions) | Level 2 |  | Level 3 |  | Level 2 |  | Level 3
Long-term debt, including current portion | $ | 9,182 |  |  | $ | 825 |  |  | $ | 9,446 |  |  | $ | — |

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 condensed consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:

| March 31, 2021
(In millions) | Total |  | Level 1 |  | Level 2 |  | Level 3
Investments in securities (classified within other current and non-current assets) | $ | 24 |  |  | $ | 10 |  |  | $ | 14 |  |  | $ | — |
Nuclear trust fund investments: |  |  |  |  |  |  |
Cash and cash equivalents | 20 |  |  | 20 |  |  | — |  |  | — |
U.S. government and federal agency obligations | 73 |  |  | 72 |  |  | 1 |  |  | — |
Federal agency mortgage-backed securities | 78 |  |  | — |  |  | 78 |  |  | — |
Commercial mortgage-backed securities | 40 |  |  | — |  |  | 40 |  |  | — |
Corporate debt securities | 136 |  |  | — |  |  | 136 |  |  | — |
Equity securities | 466 |  |  | 466 |  |  | — |  |  | — |
Foreign government fixed income securities | 7 |  |  | 1 |  |  | 6 |  |  | — |
Other trust fund investments: |  |  |  |  |  |  |
U.S. government and federal agency obligations | 1 |  |  | 1 |  |  | — |  |  | — |
Derivative assets: |  |  |  |  |  |  |
Commodity contracts | 2,824 |  |  | 195 |  |  | 2,365 |  |  | 264 |
Measured using net asset value practical expedient: |  |  |  |  |  |  |
Equity securities — nuclear trust fund investments | 89 |  |  |  |  |  |  |
Equity securities | 8 |  |  |  |  |  |  |
Total assets | $ | 3,766 |  |  | $ | 765 |  |  | $ | 2,640 |  |  | $ | 264 |
Derivative liabilities: |  |  |  |  |  |  |
Foreign exchange contracts | $ | 2 |  |  | $ | — |  |  | $ | 2 |  |  | $ | — |
Commodity contracts | 2,438 |  |  | 205 |  |  | 2,128 |  |  | 105 |
Total liabilities | $ | 2,440 |  |  | $ | 205 |  |  | $ | 2,130 |  |  | $ | 105 |

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| December 31, 2020
(In millions) | Total |  | Level 1 |  | Level 2 |  | Level 3
Investments in securities (classified within other current and non-current assets) | $ | 25 |  |  | $ | 10 |  |  | $ | 15 |  |  | $ | — |
Nuclear trust fund investments: |  |  |  |  |  |  |
Cash and cash equivalents | 23 |  |  | 23 |  |  | — |  |  | — |
U.S. government and federal agency obligations | 70 |  |  | 69 |  |  | 1 |  |  | — |
Federal agency mortgage-backed securities | 89 |  |  | — |  |  | 89 |  |  | — |
Commercial mortgage-backed securities | 36 |  |  | — |  |  | 36 |  |  | — |
Corporate debt securities | 144 |  |  | — |  |  | 144 |  |  | — |
Equity securities | 434 |  |  | 434 |  |  | — |  |  | — |
Foreign government fixed income securities | 7 |  |  | 1 |  |  | 6 |  |  | — |
Other trust fund investments: |  |  |  |  |  |  |
U.S. government and federal agency obligations | 1 |  |  | 1 |  |  | — |  |  | — |
Derivative assets: |  |  |  |  |  |  |
Commodity contracts | 821 |  |  | 59 |  |  | 623 |  |  | 139 |
Measured using net asset value practical expedient: |  |  |  |  |  |  |
Equity securities — nuclear trust fund investments | 87 |  |  |  |  |  |  |
Equity securities | 8 |  |  |  |  |  |  |
Total assets | $ | 1,745 |  |  | $ | 597 |  |  | $ | 914 |  |  | $ | 139 |
Derivative liabilities: |  |  |  |  |  |  |
Commodity contracts | $ | 884 |  |  | $ | 86 |  |  | $ | 643 |  |  | $ | 155 |
Total liabilities | $ | 884 |  |  | $ | 86 |  |  | $ | 643 |  |  | $ | 155 |

The following table reconciles, for the three months ended March 31, 2021 and 2020, the beginning and ending balances for financial instruments that are recognized at fair value in the condensed consolidated financial statements, using significant unobservable inputs:

|  |  |  | Fair Value Measurement Using Significant Unobservable Inputs (Level 3) |  |
|  |  |  | Three months ended March 31, 2021 |  |  |  |  | Three months ended March 31, 2020 |  |
(In millions) |  |  |  | Derivatives(a) |  |  |  |  |  |  | Derivatives(a) |  |
Beginning balance |  |  |  | $ | (16) |  |  |  |  |  |  |  | $ | 38 |  |  |
Contracts added from Direct Energy acquisition |  |  |  | (15) |  |  |  |  |  |  |  | — |  |  |
Total gains realized/unrealized— included in earnings |  |  |  | 180 |  |  |  |  |  |  |  | 22 |  |  |
Purchases |  |  |  | 20 |  |  |  |  |  |  |  | 8 |  |  |
Transfers into Level 3(b) |  |  |  | 4 |  |  |  |  |  |  |  | 8 |  |  |
Transfers out of Level 3(b) |  |  |  | (14) |  |  |  |  |  |  |  | (3) |  |  |
Ending balance |  |  |  | $ | 159 |  |  |  |  |  |  |  | $ | 73 |  |  |
Gains/(losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of period end |  |  |  | $ | 146 |  |  |  |  |  |  |  | $ | (9) |  |  |

(a)Consists of derivative 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 in/out are with Level 2
Derivative Fair Value Measurements
A portion of NRG'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. The remainder of the assets and liabilities represent 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 the observable market data with similar characteristics. As of March 31, 2021, contracts valued with prices provided by models and other valuation techniques make up 9% of derivative assets and 4% of derivative liabilities.
NRG's significant positions classified as Level 3 include physical and financial natural gas and power contracts executed in illiquid markets, as well as 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
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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 March 31, 2021 and December 31, 2020:

| March 31, 2021
| Fair Value |  |  |  | Input/Range
(In millions) | Assets |  | Liabilities |  | Valuation Technique |  | Significant Unobservable Input |  | Low |  | High |  | Weighted Average
Natural Gas Contracts | $ | 3 |  |  | $ | — |  |  | Discounted Cash Flow |  | Forward Market Price (per MMBtu) |  | $ | 1 |  |  | $ | 16 |  |  | $ | 14 |
Power Contracts | 234 |  |  | 91 |  |  | Discounted Cash Flow |  | Forward Market Price (per MWh) |  | 1 |  |  | 237 |  |  | 29 |
FTRs | 27 |  |  | 14 |  |  | Discounted Cash Flow |  | Auction Prices (per MWh) |  | (33) |  |  | 320 |  |  | 0
| $ | 264 |  |  | $ | 105 |  |  |  |  |  |  |  |  |  |  |

| December 31, 2020
| Fair Value |  |  |  | Input/Range
(In millions) | Assets |  | Liabilities |  | Valuation Technique |  | Significant Unobservable Input |  | Low |  | High |  | Weighted Average
Power Contracts | $ | 111 |  |  | $ | 143 |  |  | Discounted Cash Flow |  | Forward Market Price (per MWh) |  | $ | 10 |  |  | $ | 105 |  |  | $ | 21 |
FTRs | 28 |  |  | 12 |  |  | Discounted Cash Flow |  | Auction Prices (per MWh) |  | (28) |  |  | 43 |  |  | 0
| $ | 139 |  |  | $ | 155 |  |  |  |  |  |  |  |  |  |  |

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of March 31, 2021 and December 31, 2020:

Significant Unobservable Input |  | Position |  | Change In Input |  | Impact on Fair Value Measurement
Forward Market Price Natural Gas/Power |  | Buy |  | Increase/(Decrease) |  | Higher/(Lower)
Forward Market Price Natural Gas/Power |  | Sell |  | Increase/(Decrease) |  | Lower/(Higher)
FTR Prices |  | Buy |  | Increase/(Decrease) |  | Higher/(Lower)
FTR Prices |  | Sell |  | Increase/(Decrease) |  | Lower/(Higher)

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 is calculated based on published default probabilities. As of March 31, 2021, the credit reserve resulted in a $14 million decrease primarily within cost of operations. As of December 31, 2020, the credit reserve resulted in a $2 million increase primarily within cost of operations.
Concentration of Credit Risk
In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, to the Company's 2020 Form 10-K, the following is a discussion of the concentration of credit risk for the Company's contractual obligations. 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. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply arrangements, as well as retail customer credit risk through its retail load activities.
Counterparty Credit Risk
The Company's counterparty credit risk policies are disclosed in its 2020 Form 10-K. As of March 31, 2021, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $811 million and NRG held collateral (cash and letters of credit) against those positions of $140 million, resulting in a net exposure of $752 million. 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.
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Approximately 43% of the Company's exposure before collateral is expected to roll off by the end of 2022. 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.

| Net Exposure(a)(b)
Category by Industry Sector | (% of Total)
Utilities, energy merchants, marketers and other | 79 | %
Financial institutions | 21 |
Total as of March 31, 2021 | 100 | %

| Net Exposure (a)(b)
Category by Counterparty Credit Quality | (% of Total)
Investment grade | 61 | %
Non-investment grade/non-rated | 39 |
Total as of March 31, 2021 | 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 total net exposure discussed above as of March 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 $393 million. The Company is pursuing all means available to enforce its obligations 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 as of March 31, 2021.
RTOs and ISOs
The Company participates in the organized markets of CAISO, ERCOT, AESO, IESO, ISO-NE, MISO, NYISO and PJM, known as RTOs or ISOs. Trading in the majority of these markets is approved by FERC, whereas in the case of ERCOT, it is approved by the PUCT, and whereas in the case of AESO and IESO, both exist provincially with AESO primarily subject to Alberta Utilities Commission and the IESO to the Ontario Energy Board. These ISOs may 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 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 March 31, 2021, aggregate credit risk exposure managed by NRG to these counterparties was approximately $925 million for the next five years.
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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 non-payment 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 March 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. 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 — Nuclear Decommissioning Trust Fund
NRG's Nuclear Decommissioning Trust Fund assets, which are for the decommissioning of its 44% interest in STP, are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. NRG accounts for the Nuclear Decommissioning Trust Fund in accordance with ASC 980, Regulated Operations, 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 OCI, 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 March 31, 2021 |  | As of December 31, 2020
(In millions, except maturities) | Fair Value |  | Unrealized Gains |  | Unrealized Losses |  | Weighted-average Maturities (In years) |  | Fair Value |  | Unrealized Gains |  | Unrealized Losses |  | Weighted-average Maturities (In years)
Cash and cash equivalents | $ | 20 |  |  | $ | — |  |  | $ | — |  |  | — |  |  | $ | 23 |  |  | $ | — |  |  | $ | — |  |  | — |
U.S. government and federal agency obligations | 73 |  |  | 4 |  |  | 2 |  |  | 12 |  | 70 |  |  | 6 |  |  | — |  |  | 10
Federal agency mortgage-backed securities | 78 |  |  | 3 |  |  | — |  |  | 23 |  | 89 |  |  | 4 |  |  | — |  |  | 24
Commercial mortgage-backed securities | 40 |  |  | 1 |  |  | — |  |  | 28 |  | 36 |  |  | 2 |  |  | — |  |  | 27
Corporate debt securities | 136 |  |  | 7 |  |  | 1 |  |  | 12 |  | 144 |  |  | 13 |  |  | — |  |  | 12
Equity securities | 555 |  |  | 403 |  |  | — |  |  | — |  |  | 521 |  |  | 372 |  |  | — |  |  | — |
Foreign government fixed income securities | 7 |  |  | — |  |  | — |  |  | 9 |  | 7 |  |  | 1 |  |  | — |  |  | 10
Total | $ | 909 |  |  | $ | 418 |  |  | $ | 3 |  |  |  |  | $ | 890 |  |  | $ | 398 |  |  | $ | — |  |  |

The following table summarizes proceeds from sales of available-for-sale securities held in the trust funds and the related realized gains and losses from these sales. The cost of securities sold is determined on the specific identification method.

| Three months ended March 31,
(In millions) | 2021 |  | 2020
Realized gains | $ | 3 |  |  | $ | 2 |
Realized losses | (2) |  |  | (5) |
Proceeds from sale of securities | 118 |  |  | 112 |

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Note 7 — Accounting for Derivative Instruments and Hedging Activities
Energy-Related Commodities
As of March 31, 2021, NRG had energy-related derivative instruments extending through 2036. The Company marks these derivatives to market through the statement of operations. NRG has executed power purchase agreements extending through 2037 that qualified for the NPNS exception and were therefore exempt from fair value accounting treatment.
Foreign Exchange Contracts
NRG is exposed to changes in foreign currency associated with the purchase of USD denominated natural gas for its Canadian business. In order to manage the Company's foreign exchange risk, NRG entered into foreign exchange contracts. As of March 31, 2021, NRG had foreign exchange contracts extending through 2023. The Company marks these derivatives to market through the statement of operations.
Volumetric Underlying Derivative Transactions
The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by category, excluding those derivatives that qualified for the NPNS exception, as of March 31, 2021 and December 31, 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.

|  | Total Volume (In millions)
Category | Units | March 31, 2021 |  | December 31, 2020
Emissions | Short Ton | — |  |  | 1 |
Renewable Energy Certificates | Certificates | 13 |  |  | 5 |
Coal | Short Ton | 2 |  |  | 2 |
Natural Gas | MMBtu | 605 |  |  | (286) |
Power | MWh | 201 |  |  | 57 |
Capacity | MW/Day | — |  |  | (1) |
Foreign Exchange | Dollars | $ | 158 |  |  | $ | — |

The increase in positions was primarily the result of the Direct Energy acquisition.
Fair Value of Derivative Instruments
The following table summarizes the fair value within the derivative instrument valuation on the balance sheets:

| Fair Value
| Derivative Assets |  | Derivative Liabilities
(In millions) | March 31, 2021 |  | December 31, 2020 |  | March 31, 2021 |  | December 31, 2020
Derivatives Not Designated as Cash Flow or Fair Value Hedges: |  |  |  |  |  |  |
Foreign exchange contracts - current | $ | — |  |  | $ | — |  |  | $ | 1 |  |  | $ | — |
Foreign exchange contracts -long-term | — |  |  | — |  |  | 1 |  |  | — |
Commodity contracts - current | 1,816 |  |  | 560 |  |  | 1,605 |  |  | 499 |
Commodity contracts - long-term | 1,008 |  |  | 261 |  |  | 833 |  |  | 385 |
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges | $ | 2,824 |  |  | $ | 821 |  |  | $ | 2,440 |  |  | $ | 884 |

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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 of derivatives by counterparty master agreement level and collateral received or paid:

|  | Gross Amounts Not Offset in the Statement of Financial Position
(In millions) |  | Gross Amounts of Recognized Assets / Liabilities |  | Derivative Instruments |  | Cash Collateral (Held) / Posted |  | Net Amount
As of March 31, 2021 |  |  |  |  |  |  |  |
Foreign exchange contracts: |  |  |  |  |  |  |  |
Derivative liabilities |  | $ | (2) |  |  | $ | — |  |  | $ | — |  |  | $ | (2) |
Total foreign exchange contracts |  | $ | (2) |  |  | $ | — |  |  | $ | — |  |  | $ | (2) |
Commodity contracts: |  |  |  |  |  |  |  |
Derivative assets |  | $ | 2,824 |  |  | $ | (2,253) |  |  | $ | (10) |  |  | $ | 561 |
Derivative liabilities |  | (2,438) |  |  | 2,253 |  |  | — |  |  | (185) |
Total commodity contracts |  | $ | 386 |  |  | $ | — |  |  | $ | (10) |  |  | $ | 376 |
Total derivative instruments |  | $ | 384 |  |  | $ | — |  |  | $ | (10) |  |  | $ | 374 |

|  | Gross Amounts Not Offset in the Statement of Financial Position
(In millions) |  | Gross Amounts of Recognized Assets / Liabilities |  | Derivative Instruments |  | Cash Collateral (Held) / Posted |  | Net Amount
As of December 31, 2020 |  |  |  |  |  |  |  |
Commodity contracts: |  |  |  |  |  |  |  |
Derivative assets |  | $ | 821 |  |  | $ | (658) |  |  | $ | (5) |  |  | $ | 158 |
Derivative liabilities |  | (884) |  |  | 658 |  |  | — |  |  | (226) |
Total commodity contracts |  | $ | (63) |  |  | $ | — |  |  | $ | (5) |  |  | $ | (68) |

Impact of Derivative Instruments on the Statements of Operations
Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow and fair value 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 are included within operating revenues and cost of operations.

(In millions) | Three months ended March 31, |  |
Unrealized mark-to-market results | 2021 |  | 2020 |  |  |  |
Reversal of previously recognized unrealized losses on settled positions related to economic hedges | $ | 17 |  |  | $ | 9 |  |  |  |  |
Reversal of acquired loss positions related to economic hedges | 145 |  |  | 1 |  |  |  |  |
Net unrealized gains on open positions related to economic hedges | 559 |  |  | 34 |  |  |  |  |
Total unrealized mark-to-market gains for economic hedging activities | 721 |  |  | 44 |  |  |  |  |
Reversal of previously recognized unrealized (gains) on settled positions related to trading activity | (7) |  |  | (2) |  |  |  |  |
Net unrealized gains on open positions related to trading activity | 11 |  |  | 13 |  |  |  |  |
Total unrealized mark-to-market gains for trading activity | 4 |  |  | 11 |  |  |  |  |
Total unrealized gains | $ | 725 |  |  | $ | 55 |  |  |  |  |

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| Three months ended March 31, |  |
(In millions) | 2021 |  | 2020 |  |  |  |
Unrealized (losses)/gains included in operating revenues - commodities | $ | (28) |  |  | $ | 7 |  |  |  |  |
Unrealized gains included in cost of operations - commodities | 755 |  |  | 48 |  |  |  |  |
Unrealized (losses) included in cost of operations - foreign exchange | (2) |  |  | — |  |  |  |  |
Total impact to statement of operations | $ | 725 |  |  | $ | 55 |  |  |  |  |

The reversals of acquired loss 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 operating revenue or cost of operations during the same period.
For the three months ended March 31, 2021, the $559 unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward positions due to increases in ERCOT power prices and ERCOT heat rate expansion.
For the three months ended March 31, 2020, the $34 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward power positions due to decrease in West/Other power prices, as well as an increase in value of ERCOT heat rate positions due to ERCOT hear rate expansion.
Credit Risk Related Contingent Features
Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed “adequate assurance” under the agreements, or require the Company to post additional collateral if there were a 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 March 31, 2021, were still supported by credit support posted by Centrica, and as a result, could require the Company to post additional collateral upon a deterioration or downgrade of Centrica. The collateral required for contracts with adequate assurance clauses that are in a net liability position as of March 31, 2021 was $642 million. The Company is also party to certain marginable agreements under which it has net liability position, but the counterparty has not called for the collateral due, which was $91 million as of March 31, 2021. If called for by the counterparty, $57 million of additional collateral would be required for all contracts with credit rating contingent features as of March 31, 2021.
See Note 5, Fair Value of Financial Instruments, for discussion regarding concentration of credit risk.
Note 8 — Impairments
2020 Impairment Losses
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.
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Note 9 — Long-term Debt and Finance Leases
Long-term debt and finance leases consisted of the following:

(In millions, except rates) | March 31, 2021 |  | December 31, 2020 |  | Interest rate %
Recourse debt: |  |  |  |  |
Senior Notes, due 2026 | $ | 1,000 |  |  | $ | 1,000 |  |  | 7.250
Senior Notes, due 2027 | 1,230 |  |  | 1,230 |  |  | 6.625
Senior Notes, due 2028 | 821 |  |  | 821 |  |  | 5.750
Senior Notes, due 2029 | 733 |  |  | 733 |  |  | 5.250
Senior Notes, due 2029 | 500 |  |  | 500 |  |  | 3.375
Senior Notes, due 2031 | 1,030 |  |  | 1,030 |  |  | 3.625
Convertible Senior Notes, due 2048(a) | 575 |  |  | 575 |  |  | 2.750
Senior Secured First Lien Notes, due 2024 | 600 |  |  | 600 |  |  | 3.750
Senior Secured First Lien Notes, due 2025 | 500 |  |  | 500 |  |  | 2.000
Senior Secured First Lien Notes, due 2027 | 900 |  |  | 900 |  |  | 2.450
Senior Secured First Lien Notes, due 2029 | 500 |  |  | 500 |  |  | 4.450
Revolving Credit Facility | 750 |  |  | — |  |  | L + 1.720
Tax-exempt bonds | 466 |  |  | 466 |  |  | 1.250 - 4.750
Repurchase Facility | 75 |  |  | — |  |  | L + 1.250
Subtotal recourse debt | 9,680 |  |  | 8,855 |  |  |
Finance leases | 16 |  |  | 4 |  |  | various
Subtotal long-term debt and finance leases (including current maturities) | 9,696 |  |  | 8,859 |  |  |
Less current maturities | (831) |  |  | (1) |  |  |
Less debt issuance costs | (89) |  |  | (93) |  |  |
Discounts | (71) |  |  | (74) |  |  |
Total long-term debt | $ | 8,705 |  |  | $ | 8,691 |  |  |

(a)As of the ex-dividend date of January 29, 2021, the Convertible Senior Notes were convertible at a price of $45.91, which is equivalent to a conversion rate of approximately 21.79 shares of common stock per $1,000 principal amount. As of the ex-dividend date of April 30, 2021, the Convertible Senior Notes were convertible at a price of $45.54, which is equivalent to a conversion rate of approximately 21.96 shares of common stock per $1,000 principal amount
Recourse Debt
Revolving Credit Facility
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 that is 30 months after the date of closing of the Direct Energy acquisition. 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 new tranche be extended by 12 months, but not beyond 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 upon January 5, 2021. As of March 31, 2021, total revolving commitments available, subject to usage, under the amended credit agreement was $3.7 billion. As of March 31, 2021, $750 million of borrowings were outstanding. As of May 6, 2021, there were $70 million of borrowings outstanding.
Non-Recourse Debt
Put Option Agreement for Senior Debt Issuance
As further discussed in Part IV, Item 15, Note 14, Long-term Debt and Finance Leases of the Company's 2020 Form 10-K, the Company entered into a Put Option Agreement for Senior Debt Issuances (the “P-Caps”). 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
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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 (a “Collateral Enforcement Event”). The LC Agreement and the Pledge Agreement were available on January 5, 2021. As of March 31, 2021, $689 million of letters of credit were issued under the LC Agreement.
Note 10 — Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs
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. On February 3, 2021, the Company sold its 35% ownership in Agua Caliente to Clearway Energy, Inc. for $202 million as further described in Note 4, Acquisitions and Dispositions.
Variable Interest 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, Receivables Securitization and Repurchase Facility, to the Company’s 2020 Form 10-K.
The summarized financial information for the Company's consolidated VIE consisted of the following:

(In millions) | March 31, 2021 |  | December 31, 2020
Accounts receivable | $ | 728 |  |  | $ | 647 |
Other current assets | 1 |  |  | 2 |
Total assets | 729 |  |  | 649 |
Current liabilities | 76 |  |  | 78 |
Net assets | $ | 653 |  |  | $ | 571 |

Note 11 — Changes in Capital Structure
As of March 31, 2021 and December 31, 2020, the Company had 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's common stock issued and outstanding:

| Issued |  | Treasury |  | Outstanding
Balance as of December 31, 2020 | 423,057,848 |  |  | (178,825,915) |  |  | 244,231,933 |
Shares issued under LTIPs | 461,273 |  |  | — |  |  | 461,273 |
Balance as of March 31, 2021 | 423,519,121 |  |  | (178,825,915) |  |  | 244,693,206 |
Shares issued under LTIPs | 790 |  |  | — |  |  | 790 |
Shares issued under ESPP | — |  |  | 59,967 |  |  | 59,967 |
Balance as of May 6, 2021 | 423,519,911 |  |  | (178,765,948) |  |  | 244,753,963 |

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 occurs each April 1 and October 1. An exercise date occurs each September 30 and March 31.
NRG Common Stock Dividends
During the first quarter of 2021, NRG increased the annual dividend to $1.30 from $1.20 per share and expects to target an annual dividend growth rate of 7-9% per share in subsequent years. A quarterly dividend of $0.325 per share was paid on the Company's common stock during the three months ended March 31, 2021. On April 19, 2021, NRG declared a quarterly dividend on the Company's common stock of $0.325 per share, payable on May 17, 2021 to stockholders of record as of May 3, 2021.
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The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations.
Note 12 — (Loss)/Income Per Share
Basic (loss)/income per common share is computed by dividing net (loss)/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 (loss)/income per share is computed in a manner consistent with that of basic (loss)/income per share while giving effect to all potentially dilutive common shares that were outstanding during the period. 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 (loss)/income per share. However, these instruments are included in the denominator for purposes of computing diluted (loss)/income per share under the treasury stock method. The Convertible Senior Notes are convertible, under certain circumstances, into the Company’s common stock, cash or combination thereof (at NRG's option). There is no dilutive effect for the Convertible Senior Notes due to the Company’s expectation to settle the liability in cash.
The reconciliation of NRG's basic and diluted (loss)/income per share is shown in the following table:

| Three months ended March 31, |  |
(In millions, except per share data) | 2021 |  | 2020 |  |  |  |
Basic (loss)/income per share: |  |  |  |
Net (loss)/income | $ | (82) |  |  | $ | 121 |  |  |  |  |
Weighted average number of common shares outstanding - basic | 245 |  |  | 248 |  |  |  |  |
(Loss)/income per weighted average common share — basic | $ | (0.33) |  |  | $ | 0.49 |  |  |  |  |
Diluted (loss)/income per share: |  |  |  |
Net (loss)/income | $ | (82) |  |  | $ | 121 |  |  |  |  |
Weighted average number of common shares outstanding - basic | 245 |  |  | 248 |  |  |  |  |
Incremental shares attributable to the issuance of equity compensation (treasury stock method) | — |  |  | 1 |  |  |  |  |
Weighted average number of common shares outstanding - dilutive | 245 |  |  | 249 |  |  |  |  |
(Loss)/income per weighted average common share — diluted | $ | (0.33) |  |  | $ | 0.49 |  |  |  |  |

As of March 31, 2021, the Company had 1 million shares of outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company’s diluted loss per share. As of March 31, 2020, 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 13 — Segment Reporting
The Company’s segment structure reflects how management currently 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 allocation of capital, as well as net income/(loss).
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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 East segment includes the deregulated customer and market operations of Canada. The West/Services/Other segment includes activity related to the regulated operations in Alberta, Canada and the services businesses.

|  | Three months ended March 31, 2021
(In millions) |  | Texas |  | East |  | West/Services/Other |  | Corporate |  | Eliminations |  | Total
Operating revenues |  | $ | 3,702 |  |  | $ | 3,825 |  |  | $ | 565 |  |  | $ | — |  |  | $ | (1) |  |  | $ | 8,091 |
Depreciation and amortization |  | 77 |  |  | 209 |  |  | 24 |  |  | 7 |  |  | — |  |  | 317 |
Gain on sale of assets |  | — |  |  | — |  |  | 17 |  |  | — |  |  | — |  |  | 17 |
Equity in losses of unconsolidated affiliates |  | (1) |  |  | — |  |  | (5) |  |  | — |  |  | — |  |  | (6) |
(Loss)/income before income taxes |  | (425) |  |  | 357 |  |  | 70 |  |  | (169) |  |  | — |  |  | (167) |
Net (loss)/income |  | $ | (425) |  |  | $ | 353 |  |  | $ | 69 |  |  | $ | (79) |  |  | $ | — |  |  | $ | (82) |

|  | Three months ended March 31, 2020
(In millions) |  | Texas |  | East |  | West/Services/Other |  | Corporate |  | Eliminations |  | Total
Operating revenues |  | $ | 1,358 |  |  | $ | 521 |  |  | $ | 143 |  |  | $ | — |  |  | $ | (3) |  |  | $ | 2,019 |
Depreciation and amortization |  | 59 |  |  | 32 |  |  | 9 |  |  | 9 |  |  | — |  |  | 109 |
Gain on sale of assets |  | — |  |  | — |  |  | 1 |  |  | 5 |  |  | — |  |  | 6 |
Equity in losses of unconsolidated affiliates |  | — |  |  | — |  |  | (11) |  |  | — |  |  | — |  |  | (11) |
Income/(loss) before income taxes |  | 162 |  |  | 20 |  |  | 45 |  |  | (82) |  |  | (1) |  |  | 144 |
Net income/(loss) |  | $ | 162 |  |  | $ | 20 |  |  | $ | 45 |  |  | $ | (105) |  |  | $ | (1) |  |  | $ | 121 |

Note 14 — Income Taxes
Effective Income Tax Rate
The income tax provision consisted of the following:

| Three months ended March 31, |  |
(In millions, except rates) | 2021 |  | 2020 |  |  |  |
(Loss)/Income before income taxes | $ | (167) |  |  | $ | 144 |  |  |  |  |
Income tax (benefit)/expense | (85) |  |  | 23 |  |  |  |  |
Effective income tax rate | 50.9 | % |  | 16.0 | % |  |  |  |

For the three months ended March 31, 2021, the effective tax rate was higher than the statutory rate of 21% primarily due to state tax benefits and one-time tax benefits, as a result of the acquisition of Direct Energy, on the revaluation of state deferred tax assets, NOLs, and valuation allowance. For the same period in 2020, the effective tax rate was lower than the statutory rate of 21% primarily due to an excess tax benefit related to share-based compensation, partially offset by state tax expense.
Uncertain Tax Benefits
As of March 31, 2021, NRG had a non-current tax liability of $23 million for uncertain tax benefits from positions taken on various federal and state income tax returns and accrued interest. For the three months ended March 31, 2021, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of March 31, 2021, NRG had cumulative interest and penalties related to these uncertain tax benefits of $2 million. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.
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 2017. With few exceptions, state and local income tax examinations are no longer open for years prior to 2012.
Note 15 — Related Party Transactions
NRG provides services to some of its 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.
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The following table summarizes NRG's material related party transactions with third party affiliates:

| Three months ended March 31, |  |
(In millions) | 2021 |  | 2020 |  |  |  |
Revenues from Related Parties Included in Operating Revenues |  |  |  |  |  |  |
Gladstone | $ | 1 |  |  | $ | 1 |  |  |  |  |
Ivanpah(a) | 12 |  |  | 13 |  |  |  |  |
Midway-Sunset | 2 |  |  | 1 |  |  |  |  |
Total | $ | 15 |  |  | $ | 15 |  |  |  |  |

(a) Also includes fees under project management agreements with each project company
Note 16 — Commitments and Contingencies
Commitments
The Company disclosed its commitments in Note 24, Commitments and Contingencies, to the Company's 2020 Form 10-K. NRG completed the acquisition of Direct Energy on January 5, 2021 and assumed additional commitments as of the acquisition date as detailed below.
Purchased Energy Commitments
NRG assumed additional long-term contractual commitments related to electricity and natural gas products, including power purchases, gas transportation and storage. The Company's minimum commitments under such outstanding agreements are estimated as follows:

Period | (In millions)
2021 | $ | 246 |
2022 | 396 |
2023 | 272 |
2024 | 180 |
2025 | 134 |
Thereafter | 450 |
Total | $ | 1,678 |

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 may have a claim under the first lien program. As of March 31, 2021, all hedges under the first lien program were in-the-money for NRG on a counterparty aggregate basis.
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 17, Regulatory Matters, and Note 18, 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 their currently recorded accruals and that such differences could be material.
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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.
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 four putative class actions pending against Direct Energy: (1) Linda Stanley v. Direct Energy (S.D.N.Y Apr. 2019) - The parties recently agreed to mediate this matter. In the interim, all written discovery is stayed. Direct Energy plans to depose the plaintiff in the next 60 days prior to mediation; (2) Martin Forte v. Direct Energy (N.D.N.Y. Mar. 2017) - Direct Energy’s Motion for Summary Judgment and Plaintiff’s Class Certification are fully briefed and awaiting a ruling; (3) Richard Schafer v. Direct Energy (W.D.N.Y. Dec. 2019; on appeal 2nd Cir. N.Y.) - The trial court dismissed this action. Plaintiff appealed to the Second Circuit Court of Appeals. Oral arguments took place in April 2021. Subsequently, the Second Circuit issued a summary opinion vacating the district court's dismissal of the case. The matter was remanded back to the district court; and (4) Julie and Richard Lane v. Direct Energy (S.D.Ill. Jun. 2019) - Plaintiff has amended her Complaint in response to the Court dismissing all claims except a claim under the Illinois Consumer Protection Act. Direct Energy’s Motion to Dismiss is pending the Court’s ruling.
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 continues to deny the allegations asserted by plaintiffs and intends to vigorously defend these matters.
There are two putative class actions pending against Direct Energy: (1) Brittany Burk v. Direct Energy (S.D. Tex. Feb. 2019) - Written discovery is complete, and fact and expert discovery is ongoing. The briefing on Direct Energy’s Motion to Dismiss and Plaintiff’s Class Certification is complete; 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. This case is stayed pending the outcome of a Second Circuit appeal of the AAPC issue. In each case, Direct Energy has filed a Motion to Dismiss for lack of subject matter jurisdiction based on the Supreme Court’s 2020 AAPC decision invalidating the TCPA provision asserted in each case.
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.
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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. 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 17 — Regulatory Matters
Environmental regulatory matters are discussed within Note 18, Environmental Matters.
NRG operates in a highly regulated industry and is subject to regulation by various federal, state and provincial agencies. As such, NRG is affected by regulatory developments at the federal, state and provincial 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. FERC has the authority to require disgorgement of profits and to impose penalties and NRG retains any liability following the sale of the South Central Portfolio.
Note 18 — 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 CO 2 emissions from the power sector. The ACE rule requires 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). Accordingly, we expect the EPA to promulgate a new rule to regulate GHG emissions from power plants.
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Water
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. The Company is in the process of estimating the environmental capital expenditures that will be required to comply. The capital expenditures required to comply will depend on elections regarding future operations of each coal-fired unit. NRG expects to make these elections for each unit in the fourth quarter of 2021, at which time the EPA will be notified as required. Accordingly, we do not expect to provide estimates of ELG compliance costs until early 2022.
Byproducts, Wastes, Hazardous Materials and Contamination
In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. In September 2017, the EPA agreed to reconsider the rule. On July 30, 2018, the EPA promulgated a rule that amends the existing ash rule by extending some of the deadlines and providing more flexibility for compliance. On August 21, 2018, the D.C. Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy ponds. 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. The Company has updated its estimates of required environmental capital expenditures.
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ITEM 2 — 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 introduction and overview, business strategy, and changes to the business environment
during the period, including environmental and regulatory matters;
•Results of operations;
•Financial condition, addressing liquidity position, sources and uses of liquidity, capital resources and requirements,
commitments, and off-balance sheet arrangements; and
•Known trends that may affect NRG's results of operations and financial condition in the future.
As you read this discussion and analysis, refer to NRG's Condensed Consolidated Statements of Operations to this Form 10-Q, which present the results of operations for the three months ended March 31, 2021 and 2020. Also refer to NRG's 2020 Form 10-K, which includes detailed discussions of various items impacting the Company's business, results of operations and financial condition, including: General section; Strategy section; Business Overview section, including how regulation, weather, and other factors affect NRG's business; and Critical Accounting Policies and Estimates section.
Executive Summary
Introduction and Overview
NRG is an integrated power company built on dynamic retail brands with diverse generation assets. NRG brings the power of energy to customers by producing and selling electricity and related products and services in major competitive power and gas markets in the U.S. and Canada in a manner that delivers value to all of NRG's stakeholders. The Company sells energy, services, and innovative, sustainable products and services directly to retail customers under the brand names NRG, Reliant, Direct Energy, Green Mountain Energy, Stream, and XOOM Energy, as well as other brand names owned by NRG, supported by approximately 23,000 MW of generation, including approximately 4,850 MW of fossil generation assets held for sale as of March 31, 2021.
COVID-19
As the COVID-19 pandemic continues, NRG remains focused on protecting the health and well-being of its employees, while supporting its customers and the communities in which it operates and assuring the continuity of its operations. During 2020, NRG migrated a substantial portion of its employees to a remote work environment. The first COVID-19 vaccine became available in the United States in December 2020. Vaccines have become increasingly accessible since the initial rollout and all adults across the nation became eligible to receive a vaccine as of April 19, 2021. The Company is currently planning to begin returning certain employees to the offices through a phased approach expected to be completed by the end of summer..
While the pandemic presents risks to the Company's business, as further described in the Company’s 2020 Form 10-K in Part II, Item 1A — Risk Factors, there was not a material adverse impact on the Company’s results of operations for the three months ended March 31, 2021. NRG believes it has sufficient liquidity on hand to continue business operations in light of current circumstances posed by the pandemic. As disclosed in the Liquidity and Capital Resources section, the Company has total available liquidity of $3.2 billion as of March 31, 2021, consisting of cash on hand, its Revolving Credit Facility, and additional facilities.
The situation surrounding COVID-19 remains fluid and the potential for a material adverse impact on the Company exists as long as the virus impacts the level of economic activity in the United States and abroad. While the Company expects the risk to decrease as vaccinations are administered, NRG cannot reasonably estimate with any degree of certainty the full impact COVID-19, nor any resurgence of COVID-19, may have on the Company’s results of operations, financial position, and liquidity. The extent to which the COVID-19 pandemic may impact the Company’s business, operating results, financial condition, risk exposure or liquidity will depend on future developments, including the duration of the pandemic, travel restrictions, business and workforce disruptions, any resurgence of the pandemic and the effectiveness of actions taken to contain, mitigate and treat the disease.
Strategy
NRG's strategy is to maximize stockholder value through the safe production and sale of reliable power and gas to its customers in the markets it serves, while positioning the Company to provide innovative solutions to the end-use energy or service consumer. This strategy is intended to enable the Company to optimize the integrated model to generate stable and predictable cash flow, significantly strengthen earnings and cost competitiveness, and lower risk and volatility.
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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 existing assets; (iv) optimal hedging of NRG's portfolio; and (v) engaging in disciplined and transparent capital allocation.
Sustainability is an integral part of NRG's strategy and ties directly to business success, reduced risks and brand value. In 2019, NRG announced the acceleration of its science-based GHG emissions reduction goals to align with prevailing climate science, which seeks to limit global warming in the post-industrial era to 1.5 degrees Celsius. NRG is targeting a 50% reduction by 2025, from its current 2014 baseline, and net-zero emissions by 2050. The Company is on track to meet its 2025 goal.
Energy Regulatory Matters
The Company’s regulatory matters are described in the Company’s 2020 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 17, 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.
In March 2021, President Biden announced a framework for his "Build Back Better" initiative. The announced framework includes ideas to address climate change across the whole of the federal government through tax policy and research and development, among other areas of focus. Relatedly, the U.S. House Energy and Commerce Committee released the Climate Leadership and Environmental Action for our Nation's ("CLEAN") Future Act, which is expected to influence legislative drafts of the "Build Back Better" initiative. The CLEAN Future Act proposes, among other things, a clean electricity standard that would require electricity suppliers to procure and retire clean energy credits offsetting, in aggregate, 80% of the energy sold by 2030 and 100% by 2035. It would establish an auction-based mechanism for these credits and award partial credits to certain carbon-emitting generation that have lower-than-average emissions rates. Although these proposals have not yet resulted in any new legislation being enacted or regulations promulgated, NRG is closely monitoring both legislative and executive agency action and expects to be an active participant as proposals evolve into legislation. On April 22, 2021, the President announced that the United States' Nationally Defined Contribution to the international Paris Climate Agreement will be an economy-wide reduction in greenhouse gas emissions of 50-52% by 2030, relative to 2005 levels. No methodology to achieve those targets was announced, but legislation encompassing the "Build Back Better" initiative is expected to be the bulk of the effort, with more details expected to be announced by the November 2021 Conference of the Parties 26 meeting in Glasgow, Scotland.
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.
State and Provincial Energy Regulation
State Proceedings Regarding States’ Participation in the Wholesale Market — Various states, including Connecticut, New Jersey, New York and Illinois, as well as the District of Columbia have initiated proceedings to investigate resource adequacy alternatives and to consider its participation in the regional wholesale electricity market constructs, specifically withdrawal from the regional market or implementing a state-directed capacity procurement regime. Any actions taken by the states could affect market design and market prices in the respective regional markets.
Regional Regulatory Developments
NRG is affected by rule and tariff changes that occur in the ISO regions. For further discussion on regulatory developments see Note 17, Regulatory Matters.
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East/West
PJM
FERC Changes to Capacity Markets — On March 23, 2021, the Commission held its first technical conference on Resource Adequacy in the Evolving Electricity Sector to discuss the role of capacity market constructs in PJM, ISO-NE and NYISO. The technical conference included the discussion of the implications of retaining the expanded minimum offer price rule ("Expanded MOPR") in the PJM capacity market, as well as prospective alternative approaches that could replace PJM's Expanded MOPR. On April 5, 2021, the Commission issued a notice inviting post-technical conference comments seeking comments on PJM's capacity market, the implications of Expanded MOPR and potential alternatives to Expanded MOPR in PJM. The Company filed comments on April 26, 2021. Any changes to the PJM capacity market construct may impact the outcome of the Base Residual Auction to be held in December 2021 for the 2023/2024 delivery year and future auctions.
On April 22, 2021, PJM published updated Planning Period Parameters for the 2022/2023 Base Residual Auction that indicated a significant portion of Dominion zone load, presumably the Dominion Energy Virginia utility, elected the Fixed Resource Requirements ("FRR") Alternative. PJM approved the plan and adjusted the reliability requirements downward for the RTO and the respective local delivery areas. Under the existing PJM rules, an FRR election has a minimum 5-year term. Removing capacity from the auctions could impact the auction results.
Independent Market Monitor Market Seller Offer Cap Complaint — On February 21, 2019, the Independent Market Monitor filed a complaint alleging that the current Market Seller Offer Cap is too high. A number of parties, including PJM, filed protests to the filing arguing that, among other things, the Market Monitor failed to support its claim that the expected number of performance hours used to calculate the cap is overstated. 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 within 45 days. As a result of this proceeding, default market caps could be lower.
Indiana Municipal Power Agency and City of Lawrenceburg, Indiana Complaint on Station Power — On September 17, 2020, FERC issued an order in response to a complaint and request for declaratory judgement challenging the station power wholesale netting provisions in PJM's tariff. FERC found that it does not have jurisdiction over the supply of station power and the provision of station power is a retail sale subject to state jurisdiction. The order established a Section 206 proceeding and required PJM to submit a filing to show why the station service netting provisions of its tariff are just and reasonable. Lawrenceburg Power, LLC filed for rehearing, which was denied by operation of law on November 19, 2020 and they subsequently appealed to the United States Court of Appeals for the District of Columbia Circuit. The matter is pending. On November 23, 2020, PJM submitted its station power compliance filing to FERC. In an April 27, 2021 Order, FERC found that PJM's Tariff regarding station power whole netting was unjust and unreasonable, but accepted in part and rejected in part PJM's compliance filing, and required PJM to make an additional compliance filing within 30 days of the Order. This decision could affect the rates that plants pay for station power.
New England
Mystic's Complaint on Transmission Reliability Review — On June 10, 2020, Constellation Mystic Power LLC filed a complaint at FERC against ISO-NE alleging that ISO-NE violated its Tariff in its addition of language to its planning procedure and in its conduct in carrying out a competitive transmission request for proposal to address the retirements of Mystic Units 8 and 9. On August 17, 2020, FERC issued an order denying the complaint. After a rehearing that was denied by operation of law, on January 4, 2021, Constellation Mystic Power LLC filed an appeal to the D.C. Circuit. The ISO-NE auction for the 2024-2025 delivery year concluded on February 8, 2021. Subsequently, on February 18, 2021, Constellation Mystic Power LLC withdrew the appeal.
Texas
Legislative Activity Post-Winter Storm Uri — The Texas Legislature convened extensive fact-finding hearings the week after Winter Storm Uri, and subsequently has been highly engaged in policymaking in respect to the energy sector. The focuses of the legislation pertinent to the competitive power sector include the design and governance of the ERCOT wholesale market, the weatherization of sources of power and fuel supply and related infrastructure, retail customer protections for the limited number of residential customers exposed to real-time wholesale-price index products, communications protocols before and during power outage events, and the financial security of market participants and customers including a variety of securitization proposals. The legislative session concludes at the end of May, but may reconvene in special session. A significant number of legislative proposals would direct regulatory agencies, such as the PUCT, to engage in extensive rulemaking. Due to the preliminary nature of the legislation and rulemaking process, it is unclear what, if any, impact these proposals would have on the Company or the ERCOT wholesale market.
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Public Utility Commission of Texas’ Actions with Respect to Winter Storm Uri
On February 15, 2021, the PUCT issued an emergency order that required the energy prices of the ERCOT market to reflect the "Value of Lost Load" so long as load was being involuntary curtailed during Energy Emergency Alert 3 ("EEA3") conditions, as directed by ERCOT. This action effectively set the price of energy at $9,000 per megawatt-hour for the duration of the EEA3 event. Additionally, in the same order, the PUCT temporarily suspended the Low System Wide Offer Cap ("LCAP"), reasoning that if triggered it would have the unintended effect of raising the price cap of the ERCOT market above $9,000 per megawatt-hour. On February 16, 2021, the PUCT largely reaffirmed its judgement, but rescinded the retroactive applicability of its February 15, 2021 order to the early hours of February 15, 2021. Consequently, energy prices remained at $9,000/MWh from late February 15, 2021 to early February 19, 2021, when ERCOT declared the EEA3 conditions terminated.
On February 21, 2021, citing a public emergency and imperative public necessity, the PUCT issued an order directing retail electricity providers ("REP") to suspend late fees and prohibiting REPs from disconnecting residential and small commercial customers for non-payment. Although the late fee suspension was ended by the PUCT by order dated March 3, 2021, the PUCT has yet to lift its prohibition against disconnection.
On March 4, 2021, after the PUCT lifted its temporary suspension of the LCAP, ERCOT transitioned from using the System Wide Offer Cap ("SWCAP") to the LCAP, which resulted in the offer cap being reduced from $9,000 per MWh to $2,000 per MWh, or 50 times the Katy fuel index price for the balance of the year, whichever is greater. ERCOT makes the transition from the SWCAP to LCAP after a hypothetical gas-fired peaker, using actual power prices, would have made $315,000 MW/year (achieved on February 16, 2021), which is equal to three times the assumed net cost of new entry. The PUCT has instituted a rulemaking to fix the LCAP value at $2,000 per MWh. This transition of the offer cap may reduce the balance of year 2021 power prices due to the lower offer cap.
Since Winter Storm Uri, all three then-sitting PUCT commissions have resigned. The Governor has appointed Will McAdams and Peter Lake to the PUCT, designating the latter to become Chairman upon taking office. Messrs. McAdams and Lake were confirmed by the Texas State Senate during the week of April 19, 2021.
Regulatory and Legislative Activity on ERCOT Pricing during Winter Storm Uri — The ERCOT Independent Market Monitor ("IMM") proposed that the PUCT reprice the market such that prices during 32 hours of February 18 and 19 would not automatically be fixed at $9,000/MWh, reasoning that ERCOT had recalled all directives to transmission and distribution utilities to shed load by the late evening of February 17, 2021. The PUCT rejected this proposal. Thereafter, the Texas Senate passed SB2142 which directs the PUCT as recommended by the IMM, by March 20, 2021, to reprice the market such that prices during 32 hours of February 18 and 19 would not automatically be fixed at $9,000/MWh. The Texas House has not referred the bill and House leadership has come out publicly against the repricing. It appears Legislative members are now focused on securitization as a way to address the financial issues from Winter Storm Uri.
A number of parties have either moved the PUCT to rehear its February 15 and 16 orders, arguing that they were adopted without due process and in violation of law, or have directly appealed those orders to state court. The PUCT had until April 12, 2021 to consider the pending motions for rehearing and, not having taken action, these requests were considered denied by operation of law. Certain parties consequently filed a petition for judicial review in Travis County District Court on April 22. Separately, a party has also challenged the February 15 and 16 PUCT orders before the Court of Appeals for the Third District. Briefing in that matter has been scheduled into the summer.
ERCOT Defaults and Securitization Legislation — A number of market participants defaulted on their ERCOT transactions following Winter Storm Uri. Defaulting parties result in ERCOT short-paying other market participants that are owed net payments in the market operator's settlement process. The cumulative short pay amount as of April 30, 2021 totaled $2.992 billion. Two electric co-operatives represent 84% of this amount, with Brazos Electric Co-operative constituting an overall majority of the sum ($1.879 billion). Brazos has filed for bankruptcy protection and ERCOT is an unsecured creditor in the proceeding.
ERCOT's market protocols provide for the short pay to be extinguished through a process of uplift, whereby the cost of defaults is allocated to all market participants, including retailers, generators, municipal and co-operative utilities, and financial traders. However, the total amount of this uplift is limited by ERCOT's current protocols to $2.5 million per month. Consequently, it would take approximately 96 years for the current net short-pay balance to be uplifted to the market under the current market rules. NRG's undiscounted share of the uplift based on its current market share is estimated to be approximately $185 million and has been short-paid $83 million. The remaining $102 million has been discounted based on the 96 year repayment term and the present value of $12 million was recorded as an additional liability.
The legislature is actively considering proposals to securitize these default balances. If enacted, the PUCT would either be required or allowed to issue a financing order that authorizes the issuance of bonds, the proceeds of which would resolve the existing short pay, backed by a property right to a stream of payments by market participants of an ERCOT surcharge associated with the bonds' principal and interest. Other securitization proposals also have been introduced that specifically
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permit co-operatives to securitize debts, including their ERCOT defaults, and for costs associated with online reliability deployment price adders and ancillary services to be securitized. However, the details and the scope of any securitization legislation continue to be a matter of debate at the legislature.
California
California Resource Adequacy Proceedings — Since a summer 2020 heat storm that resulted in emergency load curtailments, the State of California and CAISO have embarked on numerous new regulatory activities while redirecting existing proceedings related to the topic of resource adequacy. 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. In the same docket, the CPUC approved a new demand response program for use during emergency conditions. The CPUC is also considering longer term structural reforms of the resource adequacy policy in California.
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. In a letter dated December 16, 2020 sent to the CAISO Board, MSCC indicated that it did not object to the RMR designation but noted certain permitting and maintenance requirements for RMR operation. 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.
Canada
Alberta Energy Market — In December 2020, prior to its acquisition by NRG, Direct Energy filed a Non-Energy Rate Application with the Alberta Utilities Commission ("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 Company expects an AUC decision approving the settlement agreement this year. Separately, the Company received approval from the AUC of a negotiated rate settlement for its electricity focused 2020-2022 Energy Price Setting Plan. The Company is also in the process of repaying the remainder of amounts advanced to it from the Balance 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. The COVID-19 pandemic may prevent the Company from complying with certain of its environmental requirements, which federal and state regulators have recognized. 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 new 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. The Company’s environmental matters are described in the Company’s 2020 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Note 18, Environmental Matters, to the condensed consolidated financial statements of this Form 10-Q and as follows.
Air
The CAA and the resulting regulations (as well as similar state and local requirements) have the potential to affect air emissions, operating practices and pollution control equipment required at power plants. Under the CAA, the EPA sets NAAQS for certain pollutants including SO 2, 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 CO 2 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). Accordingly, we expect the EPA to promulgate a new rule to regulate GHG emissions from power plants.
Byproducts, Wastes, Hazardous Materials and Contamination
In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. In September 2017, the EPA agreed to reconsider the rule. On July 30, 2018, the EPA promulgated a rule that amends the existing ash rule by extending some of the deadlines and providing more flexibility for compliance. On August 21, 2018, the D.C. Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy ponds. 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. The Company has updated its estimates of required environmental capital expenditures to address this revised rule.
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 Note 16, Commitments and Contingencies, to the condensed consolidated financial statements.
Nuclear Waste — The federal government's program to construct a nuclear waste repository at Yucca Mountain, Nevada was discontinued in 2010. Since 1998, the U.S. DOE has been in default of the federal government's obligations to begin accepting spent nuclear fuel, or SNF, and high-level radioactive waste, or HLW, under the Nuclear Waste Policy Act. Owners of nuclear plants, including the owners of STP, had been required to enter into contracts setting out the obligations of the owners and the U.S. DOE, including the fees to be paid by the owners for the U.S. DOE's services to license a spent fuel repository. Effective May 16, 2014, the U.S. DOE stopped collecting the fees.
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.
Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which imposed more stringent requirements (as individual permits were renewed) for wastewater
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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. The Company is in the process of estimating the environmental capital expenditures that will be required to comply. The capital expenditures required to comply will depend on elections regarding future operations of each coal-fired unit. NRG expects to make these elections for each unit in the fourth quarter of 2021 at which time the EPA will be notified as required. Accordingly, we do not expect to provide estimates of ELG compliance costs until early 2022.
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.
Significant Events
The following significant events have occurred during 2021 as further described within this Management's Discussion and Analysis and the condensed consolidated financial statements:
Extreme Weather Event in Texas During February 2021
During February 2021, Texas experienced unprecedented cold temperatures for a prolonged duration, 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.
During the quarter ended March 31, 2021, Winter Storm Uri's financial impact to loss before income taxes was a loss of $967 million. A number of factors may mitigate or increase the financial impact, such as recently proposed regulatory securitization packages, finalizing meter and settlement data, potential customer and counterparty risk including ERCOT's shortfall payments and uplift charges, and one-time cost savings.
Direct Energy Acquisition
On January 5, 2021, the Company acquired Direct Energy, 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.
The Company paid an aggregate purchase price of $3.625 billion in cash and an initial 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 a reduction of $38 million. The Company expects to receive this payment from Centrica during the second quarter of 2021. The Company also increased its collective liquidity and collateral facilities by $3.4 billion through a combination of amending its Revolving Credit Facility, amending its credit default swap facility, entering into a revolving accounts receivable financing facility, entering into an uncommitted repurchase facility and entering into multiple agreements for the issuance of letters of credit.
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. On October 21, 2019, the Company had repaid the Agua Caliente Borrower 1 notes associated with the project of $83 million.
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Sale of 4.8 GW of Fossil Generation Assets
On February 28, 2021, the Company entered into a definitive purchase agreement with Generation Bridge, an affiliate of ArcLight Capital Partners, to sell approximately 4,850 MW of fossil generating assets from its East and West regions of operations for total proceeds of $760 million, subject to standard purchase price adjustments and certain other indemnifications. As part of the transaction, NRG is entering into a tolling agreement for its 866 MW Arthur Kill plant in New York City through April 2025.
The transaction is expected to close in the fourth quarter of 2021, and is subject to various closing conditions, approvals and consents, including FERC, NYSPSC, and antitrust review under the Hart-Scott-Rodino Act.
Renewable Power Purchase Agreements
The Company's strategy is to procure mid to long-term generation through power purchase agreements. As of March 31, 2021, NRG has entered into PPAs totaling approximately 2.2 GW with third-party project developers and other counterparties. The tenor of these agreements is an average between twelve and thirteen years. The Company expects to continue evaluating and executing similar agreements that support the needs of the business. Due to COVID-19, certain of these PPA contracts have been amended to allow for the delay of project completion dates from mid-2021 into 2022. These amendments include improved terms for NRG.
Trends Affecting Results of Operations and Future Business Performance
The Company’s trends are described in the Company’s 2020 Form 10-K in Item 7, M anagement’s Discussion and Analysis of Financial Condition and Results of Operations - Business Environment.
Changes in Accounting Standards
See Note 2, Summary of Significant Accounting Policies, for a discussion of recent accounting developments.
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Consolidated Results of Operations
The following table provides selected financial information for the Company:

| Three months ended March 31, |  |
(In millions, except as otherwise noted) | 2021 |  | 2020 |  | Change |  |  |  |  |  |
Operating Revenues |  |  |  |  |  |  |  |  |  |  |
Retail revenue | $ | 6,162 |  |  | $ | 1,661 |  |  | $ | 4,501 |  |  |  |  |  |  |
Energy revenue(a) | 482 |  |  | 124 |  |  | 358 |  |  |  |  |  |  |
Capacity revenue(a) | 155 |  |  | 149 |  |  | 6 |  |  |  |  |  |  |
Mark-to-market for economic hedging activities | (32) |  |  | (4) |  |  | (28) |  |  |  |  |  |  |
Other revenues(a)(b) | 1,324 |  |  | 89 |  |  | 1,235 |  |  |  |  |  |  |
Total operating revenues | 8,091 |  |  | 2,019 |  |  | 6,072 |  |  |  |  |  |  |
Operating Costs and Expenses |  |  |  |  |  |  |  |  |  |  |
Cost of Sales (c) | 7,183 |  |  | 1,149 |  |  | (6,034) |  |  |  |  |  |  |
Mark-to-market for economic hedging activities | (753) |  |  | (48) |  |  | 705 |  |  |  |  |  |  |
Contract and emissions credit amortization (c) | 1 |  |  | 1 |  |  | — |  |  |  |  |  |  |
Operations and maintenance | 352 |  |  | 293 |  |  | (59) |  |  |  |  |  |  |
Other cost of operations | 81 |  |  | 62 |  |  | (19) |  |  |  |  |  |  |
Total cost of operations | 6,864 |  |  | 1,457 |  |  | (5,407) |  |  |  |  |  |  |
Depreciation and amortization | 317 |  |  | 109 |  |  | (208) |  |  |  |  |  |  |
Selling, general and administrative costs | 330 |  |  | 190 |  |  | (140) |  |  |  |  |  |  |
Provision for credit losses | 611 |  |  | 24 |  |  | (587) |  |  |  |  |  |  |
Acquisition-related transaction and integration costs | 42 |  |  | 1 |  |  | (41) |  |  |  |  |  |  |
Total operating costs and expenses | 8,164 |  |  | 1,781 |  |  | (6,383) |  |  |  |  |  |  |
Gain on sale of assets | 17 |  |  | 6 |  |  | 11 |  |  |  |  |  |  |
Operating (Loss)/Income | (56) |  |  | 244 |  |  | (300) |  |  |  |  |  |  |
Other (Expense)/Income |  |  |  |  |  |  |  |  |  |  |
Equity in losses of unconsolidated affiliates | (6) |  |  | (11) |  |  | 5 |  |  |  |  |  |  |
Impairment losses on investments | — |  |  | (18) |  |  | 18 |  |  |  |  |  |  |
Other income, net | 22 |  |  | 27 |  |  | (5) |  |  |  |  |  |  |
Interest expense | (127) |  |  | (98) |  |  | (29) |  |  |  |  |  |  |
Total other expense | (111) |  |  | (100) |  |  | (11) |  |  |  |  |  |  |
(Loss)/Income Before Income Taxes | (167) |  |  | 144 |  |  | (311) |  |  |  |  |  |  |
Income tax (benefit)/expense | (85) |  |  | 23 |  |  | 108 |  |  |  |  |  |  |
Net (Loss)/Income | $ | (82) |  |  | $ | 121 |  |  | $ | (203) |  |  |  |  |  |  |
Business Metrics |  |  |  |  |  |  |  |  |  |  |
Average natural gas price — Henry Hub ($/MMBtu) | $ | 2.69 |  |  | $ | 1.95 |  |  | 38 | % |  |  |  |  |  |

(a) Includes gains and losses from financially settled transactions
(b) Includes trading gains and losses and ancillary revenues
(c) Includes amortization of SO 2 and NO x credits and excludes amortization of RGGI credits
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Management’s discussion of the results of operations for the three months ended March 31, 2021 and 2020
Electricity Prices
The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the three months ended March 31, 2021 and 2020. The average on-peak power prices increased significantly in Texas due to the impact from Winter Storm Uri. East and West/Other on-peak power prices increased due to higher gas prices, especially in February and March, driven by cold winter weather.

| Average on Peak Power Price ($/MWh)
| Three months ended March 31,
Region | 2021 |  | 2020 |  | Change %
Texas |  |  |  |  |
ERCOT - Houston(a) | $ | 619.94 |  |  | $ | 25.33 |  |  | 2,347 | %
ERCOT - North(a) | 621.04 |  |  | 24.43 |  |  | 2,442 | %
East |  |  |  |  |
NY J/NYC(b) | $ | 47.71 |  |  | $ | 23.83 |  |  | 100 | %
NEPOOL(b) | 55.26 |  |  | 24.61 |  |  | 125 | %
COMED (PJM)(b) | 33.51 |  |  | 21.29 |  |  | 57 | %
PJM West Hub(b) | 35.09 |  |  | 22.47 |  |  | 56 | %
West/Other |  |  |  |  |
MISO - Louisiana Hub(b) | $ | 40.70 |  |  | $ | 22.14 |  |  | 84 | %
CAISO - SP15(b) | 44.74 |  |  | 28.64 |  |  | 56 | %

(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 three months ended March 31, 2021 and 2020:

| Average Realized Power Price ($/MWh)
| Three months ended March 31,
Region | 2021 |  | 2020 |  | Change %
East(a) | $ | 41.29 |  |  | $ | 40.63 |  |  | 2 | %
West/Other | 34.50 |  |  | 29.31 |  |  | 18 |

(a) Average Realized Power Price reflects energy sales from the generation fleet, omitting sales to the retail component of the East Segment. Intercompany financial transactions hedging generation with the retail business make up $2.47/MWh in the three months ended March 31, 2021 and $22.88/MWh in the three months ended March 31, 2020
The average realized power prices increased in West/Other for the three months ended March 31, 2021 as compared to the same period in 2020 due to higher electricity prices as a result of increased natural gas prices.
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Winter Storm Uri
During the quarter ended March 31, 2021, Winter Storm Uri's financial impact to loss before income taxes was a loss of $967 million. The following impacts are further discussed in the related sections below:

(In millions) | Three months ended March 31, 2021
Gross margin - Texas | $ | (528) |
Gross margin - East | 154 |
Gross margin - West/Services/Other | 13 |
Total gross margin | (361) |
Selling, general and administrative costs | (21) |
Provision for credit losses | (585) |
Total impact to loss before income taxes | $ | (967) |

A number of factors may mitigate or increase the financial impact, such as recently proposed regulatory securitization packages, finalizing meter and settlement data, potential customer and counterparty risk including ERCOT's shortfall payments and uplift charges, and one-time cost savings.
Gross Margin
The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of sales, which includes cost of fuel, other costs of sales, contract and emission credit amortization and mark-to-market for economic hedging activities.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales. Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emission credit amortization, or other operating costs.
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The below tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended March 31, 2021 and 2020:

| Three months ended March 31, 2021
($ In millions) | Texas |  | East |  | West/Services/Other |  |  |  |  | Corporate/Eliminations |  | Total
Retail revenue | $ | 2,114 |  |  | $ | 3,543 |  |  | $ | 505 |  |  |  |  |  | $ | — |  |  | $ | 6,162 |
Energy revenue | 285 |  |  | 126 |  |  | 70 |  |  |  |  |  | 1 |  |  | 482 |
Capacity revenue | — |  |  | 141 |  |  | 14 |  |  |  |  |  | — |  |  | 155 |
Mark-to-market for economic hedging activities | (1) |  |  | (4) |  |  | (28) |  |  |  |  |  | 1 |  |  | (32) |
Other revenue(a) | 1,304 |  |  | 19 |  |  | 4 |  |  |  |  |  | (3) |  |  | 1,324 |
Operating revenue | 3,702 |  |  | 3,825 |  |  | 565 |  |  |  |  |  | (1) |  |  | 8,091 |
Cost of fuel | (724) |  |  | (18) |  |  | (25) |  |  |  |  |  | — |  |  | (767) |
Purchased power | (986) |  |  | (2,509) |  |  | (172) |  |  |  |  |  | — |  |  | (3,667) |
Other cost of sales(b)(c) | (1,896) |  |  | (594) |  |  | (259) |  |  |  |  |  | — |  |  | (2,749) |
Mark-to-market for economic hedging activities | 525 |  |  | 166 |  |  | 63 |  |  |  |  |  | (1) |  |  | 753 |
Contract and emission credit amortization | (1) |  |  | — |  |  | — |  |  |  |  |  | — |  |  | (1) |
Gross margin | $ | 620 |  |  | $ | 870 |  |  | $ | 172 |  |  |  |  |  | $ | (2) |  |  | $ | 1,660 |
Less: Mark-to-market for economic hedging activities, net | 524 |  |  | 162 |  |  | 35 |  |  |  |  |  | — |  |  | 721 |
Less: Contract and emission credit amortization, net | (1) |  |  | — |  |  | — |  |  |  |  |  | — |  |  | (1) |
Economic gross margin | $ | 97 |  |  | $ | 708 |  |  | $ | 137 |  |  |  |  |  | $ | (2) |  |  | $ | 940 |
(a) Includes trading gains and losses and ancillary revenues |  |  |  |  |  |  |  |  |
(b) Includes capacity and emissions credits
(c) Includes $590 million and $38 million of TDSP expense in Texas and East, respectively |  |  |  |  |  |  |  |  |
Business Metrics |  |  |  |  |  |  |  |  |  |  |  |
Home electricity sales volume (GWh) | 10,186 |  |  | 4,076 |  |  | 320 |  |  |  |  |  |  |  | 14,582 |
Business electricity sales volume (GWh) | 6,524 |  |  | 13,838 |  |  | 630 |  |  |  |  |  |  |  | 20,992 |
Home natural gas sales volume (MDth) | — |  |  | 42,434 |  |  | 35,696 |  |  |  |  |  |  |  | 78,130 |
Business natural gas sales volume (MDth) | — |  |  | 264,588 |  |  | — |  |  |  |  |  |  |  | 264,588 |
Average retail Home customer count (in thousands) (a) | 3,082 |  |  | 1,947 |  |  | 552 |  |  |  |  |  |  |  | 5,581 |
Ending retail Home customer count (in thousands) (a) | 3,086 |  |  | 2,042 |  |  | 553 |  |  |  |  |  |  |  | 5,681 |
GWh sold | 7,349 |  |  | 3,245 |  |  | 2,029 |  |  |  |  |  |  |  | 12,623 |
GWh generated:(b) |  |  |  |  |  |  |  |  |  |  |  |
Coal | 3,840 |  |  | 1,301 |  |  | — |  |  |  |  |  |  |  | 5,141 |
Gas | 1,185 |  |  | 107 |  |  | 1,985 |  |  |  |  |  |  |  | 3,277 |
Nuclear | 2,324 |  |  | — |  |  | — |  |  |  |  |  |  |  | 2,324 |
Oil | — |  |  | 17 |  |  | — |  |  |  |  |  |  |  | 17 |
Total | 7,349 |  |  | 1,425 |  |  | 1,985 |  |  |  |  |  |  |  | 10,759 |
(a) Home customer count includes recurring residential and small commercial customers, including municipal aggregations |  |  |  |  |  |  |
(b) Includes owned and leased generation, and excludes equity investments |  |  |  |  |  |  |  |  |  |  |  |

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| Three months ended March 31, 2020
($ In millions) | Texas |  | East |  | West/Services/Other |  |  |  | Corporate/Eliminations |  | Total
Retail revenue | $ | 1,292 |  |  | $ | 352 |  |  | $ | 18 |  |  |  |  | $ | (1) |  |  | $ | 1,661 |
Energy revenue | 5 |  |  | 45 |  |  | 75 |  |  |  |  | (1) |  |  | 124 |
Capacity revenue | — |  |  | 134 |  |  | 15 |  |  |  |  | — |  |  | 149 |
Mark-to-market for economic hedging activities | — |  |  | (20) |  |  | 15 |  |  |  |  | 1 |  |  | (4) |
Other revenue | 61 |  |  | 10 |  |  | 20 |  |  |  |  | (2) |  |  | 89 |
Operating revenue | 1,358 |  |  | 521 |  |  | 143 |  |  |  |  | (3) |  |  | 2,019 |
Cost of fuel | (103) |  |  | (55) |  |  | (36) |  |  |  |  | — |  |  | (194) |
Purchased power | (265) |  |  | (152) |  |  | (6) |  |  |  |  | — |  |  | (423) |
Other cost of sales(a)(b) | (462) |  |  | (81) |  |  | 10 |  |  |  |  | 1 |  |  | (532) |
Mark-to-market for economic hedging activities | 49 |  |  | — |  |  | — |  |  |  |  | (1) |  |  | 48 |
Contract and emission credit amortization | (1) |  |  | — |  |  | — |  |  |  |  | — |  |  | (1) |
Gross margin | $ | 576 |  |  | $ | 233 |  |  | $ | 111 |  |  |  |  | $ | (3) |  |  | $ | 917 |
Less: Mark-to-market for economic hedging activities, net | 49 |  |  | (20) |  |  | 15 |  |  |  |  | — |  |  | 44 |
Less: Contract and emission credit amortization, net | (1) |  |  | — |  |  | — |  |  |  |  | — |  |  | (1) |
Economic gross margin | $ | 528 |  |  | $ | 253 |  |  | $ | 96 |  |  |  |  | $ | (3) |  |  | $ | 874 |
(a) Includes capacity and emissions credits
(b) Includes $429 million and $2 million of TDSP expense in Texas and East, respectively |  |  |  |  |  |  |  |
Business Metrics |  |  |  |  |  |  |  |  |  |  |
Home electricity sales volume (GWh) | 7,748 |  |  | 2,548 |  |  | — |  |  |  |  |  | 10,296 |
Business electricity sales volume (GWh) | 4,456 |  |  | 389 |  |  | — |  |  |  |  |  | 4,845 |
Home natural gas sales volume (MDth) | — |  | 10,509 |  | — |  |  |  |  |  | 10,509
Average retail Home customer count (in thousands)(a) | 2,442 |  | 1,220 |  | — |  |  |  |  |  | 3,662
Ending retail Home customer count (in thousands)(a) | 2,439 |  | 1,212 |  | — |  |  |  |  |  | 3,651
GWh sold | 6,036 |  | 2,535 |  | 2,559 |  |  |  |  |  | 11,130
GWh generated(b) |  |  |  |  |  |  |  |  |  |  |
Coal | 3,060 |  |  | 335 |  | — |  |  |  |  |  | 3,395 |
Gas | 674 |  |  | 149 |  | 2,355 |  |  |  |  |  | 3,178 |
Nuclear | 2,302 |  |  | — |  | — |  |  |  |  |  | 2,302 |
Oil | — |  | 18 |  | — |  |  |  |  |  | 18 |
Total | 6,036 |  |  | 502 |  |  | 2,355 |  |  |  |  |  |  | 8,893 |
(a) Home customer count includes recurring residential and small commercial customers, including municipal aggregations |  |  |  |  |  |
(b) Includes owned and leased generation, and excludes equity investments |  |  |  |  |  |  |  |  |  |  |

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The table below represents the weather metrics for the three months ended March 31, 2021 and 2020:

| Three months ended March 31, |  |  |  |  |  |  |
Weather Metrics | Texas |  | East |  | West/Services/Other (b) |  |  |  |  |  |  |  |
2021 |  |  |  |  |  |  |  |  |  |  |  |  |
CDDs (a) | 86 |  |  | 38 |  |  | 37 |  |  |  |  |  |  |  |  |
HDDs (a) | 1,120 |  |  | 2,350 |  |  | 1,201 |  |  |  |  |  |  |  |  |
2020 |  |  |  |  |  |  |  |  |  |  |  |  |
CDDs | 170 |  |  | 56 |  |  | 76 |  |  |  |  |  |  |  |  |
HDDs | 791 |  |  | 2,045 |  |  | 994 |  |  |  |  |  |  |  |  |
10-year average |  |  |  |  |  |  |  |  |  |  |  |  |
CDDs | 116 |  |  | 38 |  |  | 51 |  |  |  |  |  |  |  |  |
HDDs | 937 |  |  | 2,397 |  |  | 1,067 |  |  |  |  |  |  |  |  |

(a) National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period
(b) 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
Gross Margin and Economic Gross Margin
Gross margin increased $743 million and economic gross margin increased $66 million during the three months ended March 31, 2021, compared to the same period in 2020.
The tables below describe the changes in gross margin and economic gross margin by segment:
Texas

| (In millions)
Lower gross margin due to Winter Storm Uri, primarily driven by an increase in unhedgeable ancillary and operating reserve demand curve supply costs | $ | (528) |
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 | 91 |
Higher gross margin primarily due to lower costs to serve the retail load, primarily driven by a 9% reduction of average power and fuel prices | 34 |
Lower net revenue due to lower volumes from the impact of weather of $14 million, and lower net revenue rates driven by customer term, product, mix of $0.75 per MWh, or $9 million. | (23) |
Lower gross margin from market optimization activities | (9) |
Other | 4 |
Decrease in economic gross margin | $ | (431) |
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | 475 |
Increase in gross margin | $ | 44 |

49

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 |  | $ | 154 |
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 $202 million from natural gas and $72 million from electricity |  | 274 |
Higher gross margin due to a lower of cost or market adjustment on oil inventory in 2020 |  | 29 |
Lower gross margin due to a decrease in realized power pricing, partially offset by an increase in economic generation volumes primarily at Midwest Generation |  | (8) |
Other |  | 6 |
Increase in economic gross margin |  | $ | 455 |
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges |  | 182 |
Increase in gross margin |  | $ | 637 |

West/Services/Other

| (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 | $ | 13 |
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 | 85 |
Lower gross margin due to generation outage insurance proceeds received in 2020 | (30) |
Lower gross margin due to lower economic dispatch and lower average realized pricing associated with current year outages at Cottonwood | (16) |
Lower gross margin due to commercial optimization activities | (8) |
Other | (3) |
Increase in economic gross margin | $ | 41 |
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | 20 |
Increase in gross margin | $ | 61 |

50

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 $677 million during the three months ended March 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:

| Three months ended March 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 | $ | — |  |  | $ | (15) |  |  | $ | (4) |  |  |  |  | $ | — |  |  | $ | (19) |
Reversal of acquired (gain) positions related to economic hedges | — |  |  | (3) |  |  | — |  |  |  |  | — |  |  | (3) |
Net unrealized (losses)/gains on open positions related to economic hedges | (1) |  |  | 14 |  |  | (24) |  |  |  |  | 1 |  |  | (10) |
Total mark-to-market (losses) in operating revenues | $ | (1) |  |  | $ | (4) |  |  | $ | (28) |  |  |  |  | $ | 1 |  |  | $ | (32) |
Mark-to-market results in operating costs and expenses |  |  |  |  |  |  |  |  |  |  |
Reversal of previously recognized unrealized losses on settled positions related to economic hedges | $ | 33 |  |  | $ | 3 |  |  | $ | — |  |  |  |  | $ | — |  |  | $ | 36 |
Reversal of acquired loss positions related to economic hedges | 36 |  |  | 112 |  |  | — |  |  |  |  | — |  |  | 148 |
Net unrealized gains on open positions related to economic hedges | 456 |  |  | 51 |  |  | 63 |  |  |  |  | (1) |  |  | 569 |
Total mark-to-market gains in operating costs and expenses | $ | 525 |  |  | $ | 166 |  |  | $ | 63 |  |  |  |  | $ | (1) |  |  | $ | 753 |

| Three months ended March 31, 2020
(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 | $ | — |  |  | $ | (14) |  |  | $ | (5) |  |  |  |  | $ | 1 |  |  | $ | (18) |
Net unrealized (losses)/gains on open positions related to economic hedges | — |  |  | (6) |  |  | 20 |  |  |  |  | — |  |  | 14 |
Total mark-to-market (losses)/gains in operating revenues | $ | — |  |  | $ | (20) |  |  | $ | 15 |  |  |  |  | $ | 1 |  |  | $ | (4) |
Mark-to-market results in operating costs and expenses |  |  |  |  |  |  |  |  |  |  |
Reversal of previously recognized unrealized losses on settled positions related to economic hedges | $ | 22 |  |  | $ | 6 |  |  | $ | — |  |  |  |  | $ | (1) |  |  | $ | 27 |
Reversal of acquired loss/(gain) positions related to economic hedges | 2 |  |  | (1) |  |  | — |  |  |  |  | — |  |  | 1 |
Net unrealized gains/(losses) on open positions related to economic hedges | 25 |  |  | (5) |  |  | — |  |  |  |  | — |  |  | 20 |
Total mark-to-market gains in operating costs and expenses | $ | 49 |  |  | $ | — |  |  | $ | — |  |  |  |  | $ | (1) |  |  | $ | 48 |

`
Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.
For the three months ended March 31, 2021, the $32 million loss in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period as well as a decrease in the value of open positions as a result of increases in West power prices. The $753 million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of open positions as a result of increases in ERCOT power prices and ERCOT heat rate expansion, as well as the reversal of acquired deals and previously recognized unrealized losses on contracts that settled during the period.
For the three months ended March 31, 2020, the $4 million loss in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period, largely offset by an increase in the value of open positions, as a result of gains on power positions due to declines in West/Services/Other power prices. The $48 million gain in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period, as well as gains on ERCOT heat rate positions due to heat rate expansion.
51

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended March 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 based on the Company's Risk Management Policy.

| Three months ended March 31,
(In millions) | 2021 |  | 2020
Trading gains |  |  |
Realized | $ | 59 |  |  | $ | 7 |
Unrealized | 4 |  |  | 11 |
Total trading gains | $ | 63 |  |  | $ | 18 |

Operations and Maintenance Expense
Operations and maintenance expense are comprised of the following:

(In millions) | Texas |  | East |  | West/Services/Other |  | Corporate |  | Eliminations |  | Total
Three months ended March 31, 2021 | $ | 186 |  |  | $ | 114 |  |  | $ | 53 |  |  | $ | — |  |  | $ | (1) |  |  | $ | 352 |
Three months ended March 31, 2020 | 175 |  |  | 88 |  |  | 30 |  |  | 2 |  |  | (2) |  |  | 293 |

Operations and maintenance expense increased by $59 million for the three months ended March 31, 2021, compared to the same period in 2020, primarily due to the Direct Energy acquisition in January 2021.
Other Cost of Operations
Other cost of operations are comprised of the following:

(In millions) | Texas |  | East |  | West/Services/Other |  | Total
Three months ended March 31, 2021 | $ | 43 |  |  | $ | 36 |  |  | $ | 2 |  |  | $ | 81 |
Three months ended March 31, 2020 | 33 |  |  | 26 |  |  | 3 |  |  | 62 |

Other costs of operations increased $19 million for the three months ended March 31, 2021, compared to the same period in 2020, primarily due to the Direct Energy acquisition in January 2021.
Depreciation and Amortization
Depreciation and amortization are comprised of the following:

(In millions) | Texas |  | East |  | West/Services/Other |  | Corporate |  | Total
Three months ended March 31, 2021 | $ | 77 |  |  | $ | 209 |  |  | $ | 24 |  |  | $ | 7 |  |  | $ | 317 |
Three months ended March 31, 2020 | 59 |  |  | 32 |  |  | 9 |  |  | 9 |  |  | 109 |

Depreciation and amortization increased by $208 million primarily due to the acquisition of Direct Energy in January 2021.
52

Selling, General and Administrative Costs
Selling, general and administrative costs are comprised of the following:

(In millions) | Texas |  | East |  | West/Services/Other |  | Corporate |  | Total
Three months ended March 31, 2021 | $ | 139 |  |  | $ | 147 |  |  | $ | 34 |  |  | $ | 10 |  |  | $ | 330 |
Three months ended March 31, 2020 | 108 |  |  | 61 |  |  | 13 |  |  | 8 |  |  | 190 |

Selling, general and administrative costs increased by $140 million for the three months ended March 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 | $ | 116 |
Increase due to Winter Storm Uri, including default charges in ERCOT of $12 million and legal and other costs and charitable giving of $9 million | 21 |
Other | 3 |
Increase in selling, general and administrative costs | $ | 140 |

Provision for Credit Losses
Provision for credit losses are comprised of the following:

(In millions) | Texas |  | East |  | West/Services/Other |  | Corporate |  | Total
Three months ended March 31, 2021 | $ | 602 |  |  | $ | 7 |  |  | $ | 2 |  |  | $ | — |  |  | $ | 611 |
Three months ended March 31, 2020 | 23 |  |  | 1 |  |  | — |  |  | — |  |  | 24 |

| (In millions)
Increase due to Winter Storm Uri, including: Increase of $393 million related to bilateral financial hedging risk Increase of $109 million related to counterparty credit risk Increase of $83 million related to ERCOT default shortfall payments | $ | 585 |
Increase due to acquisition of Direct Energy in January 2021, partially offset by improved collections | 2
Increase in provision for credit losses | $ | 587 |

Acquisition-Related Transaction and Integration Costs
Acquisition-related transaction and integration costs of $42 million were incurred during the three months ended March 31, 2021, related to Direct Energy, of which $22 million were acquisition-related transaction costs and $20 million were integration costs primarily related to severance and consulting services.
Gain on sale of assets
A gain on the sale of assets of $17 million was recorded for the three months ended March 31, 2021 due to the sale of Agua Caliente in February 2021 and $6 million for the three months ended March 31, 2020 related to the sale of land and investments in January 2020.
Impairment losses on investments
Impairment losses on investments of $18 million were recorded during the three months ended March 31, 2020 related to the impairment of Petra Nova Parish Holdings, as further discussed in Note 8, Impairments.
Interest Expense
Interest expense increased by $29 million for the three months ended March 31, 2021, compared to the same period in 2020, primarily due to financings entered into in connection with the Direct Energy acquisition.
53

Income Tax (Benefit)/Expense
For the three months ended March 31, 2021, an income tax benefit of $85 million was recorded on a pre-tax loss of $167 million. For the same period in 2020, income tax expense of $23 million was recorded on pre-tax income of $144 million. The effective tax rates were 50.9% and 16.0% for the three months ended March 31, 2021 and 2020, respectively.
For the three months ended March 31, 2021, the effective tax rate was higher than the statutory rate of 21% primarily due to state tax benefits and one-time tax benefits, as a result of the acquisition of Direct Energy, on the revaluation of state deferred tax assets, NOLs, and valuation allowance. For the same period in 2020, the effective tax rate was lower than the statutory rate of 21%, primarily due to an excess tax benefit related to share-based compensation, partially offset by state tax expense.
Liquidity and Capital Resources
Liquidity Position
As of March 31, 2021 and December 31, 2020, NRG's total liquidity, excluding funds deposited by counterparties, of approximately $3.2 billion and $7.0 billion, respectively, was comprised of the following:

(In millions) | March 31, 2021 |  | December 31, 2020
Cash and cash equivalents | $ | 501 |  |  | $ | 3,905 |
Restricted cash - operating | 13 |  |  | 3 |
Restricted cash - reserves(a) | 5 |  |  | 3 |
Total | 519 |  |  | 3,911 |
Total availability under Revolving Credit Facility and collective collateral facilities(b) | 2,724 |  |  | 3,129 |
Total liquidity, excluding funds deposited by counterparties | $ | 3,243 |  |  | $ | 7,040 |

(a) Includes reserves primarily for performance obligations and capital expenditures
(b) Total capacity of Revolving Credit Facility and collective collateral facilities was $5.8 billion and $4.0 billion as of March 31, 2021 and December 31, 2020, respectively
For the three months ended March 31, 2021, total liquidity, excluding funds deposited by counterparties, decreased by $3,797 million. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at March 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.
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 March 19, 2021, Moody's changed NRG's rating outlook to stable from positive. At the same time, Moody's affirmed NRG's corporate family rating of Ba1.
Liquidity
The principal sources of liquidity for NRG's future operating and maintenance capital expenditures are expected to be derived from cash on hand, cash flows from operations, and financing arrangements, as described in Note 9, Long-term Debt and Finance Leases, to this Form 10-Q. 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; (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.
Direct Energy Acquisition
On January 5, 2021, the Company acquired Direct Energy, 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 strengthens its integrated model. It also broadens the Company's presence in the Northeast and into states and locales where it did not currently operate, supporting NRG's objective to diversify its business.
54

The Company paid an aggregate purchase price of $3.625 billion in cash and an initial purchase price adjustment of $77 million. The Company funded the purchase price using a combination of $715 million 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 a reduction of $38 million. The Company expects to receive this payment from Centrica during the second quarter of 2021. The Company also increased its liquidity and collateral facilities by $3.4 billion through a combination of new letter of credit facilities and increases to its existing Revolving Credit Facility, as further described in Note 4, Acquisitions and Dispositions.
Collateral Facility Increases
The following table presents increases to the Company's collective collateral facilities in connection with the Direct Energy acquisition.

| (In millions)
Available on Acquisition Closing Date |
Revolving Credit Facility commitment increase | $ | 802 |
Revolving Credit Facility new tranche | 273 |
Facility agreement in connection with the sale of pre-capitalized trust securities | 874 |
Available as of December 31, 2020 |
Credit default swap facility | 150 |
Revolving accounts receivable financing facility | 750 |
Repurchase facility | 75 |
Bilateral letter of credit facilities | 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 debt reduction program will extend into 2022. The Company remains committed to maintaining a strong balance sheet and continues to work closely with rating agencies to achieve investment grade credit ratings.
Revolving Credit Facility
The Company had $750 million outstanding under its Revolving Credit Facility as of March 31, 2021.
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 4.8 GW of Fossil Generation Assets
On February 28, 2021, the Company entered into a definitive purchase agreement with Generation Bridge, an affiliate of ArcLight Capital Partners, to sell approximately 4,850 MW of fossil generating assets from its East and West regions of operations for total proceeds of $760 million, subject to standard purchase price adjustments and certain other indemnifications. As part of the transaction, NRG is entering into a tolling agreement for its 866 MW Arthur Kill plant in New York City through April 2025.
The transaction is expected to close in the fourth quarter of 2021, and is subject to various closing conditions, approvals and consents, including FERC, NYSPSC, and antitrust review under the Hart-Scott-Rodino Act.
Pension Plan Contributions
The American Rescue Plan Act ("ARPA") was enacted on March 11, 2021 to provide economic relief related to the COVID-19 pandemic. ARPA provides pension funding relief for single employer plans, among other provisions. As a result, NRG has reduced its previously planned cash contribution for 2021 by approximately $23 million. NRG’s pension and postretirement benefit plans are further described in Note 16, Benefit Plans and Other Postretirement Benefits, of Part IV, Item 15 of the Company’s 2020 Form 10-K.
55

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 will be payable to social security in 2021 and $13 million will be payable in 2022.
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 (i.e., buying fuel before receiving energy revenues); and (iv) initial collateral for large structured transactions. As of March 31, 2021, the Company had total cash collateral outstanding of $286 million and $2,280 million outstanding in letters of credit to third parties primarily to support its market activities. As of March 31, 2021, total funds deposited by counterparties were $42 million in cash and $290 million of letters of credit.
Future liquidity requirements may change based on the Company's hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements depend 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 March 31, 2021, all hedges under the first liens were in-the-money on a counterparty aggregate basis.
The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of March 31, 2021:

Equivalent Net Sales Secured by First Lien Structure(a) | 2021 |  | 2022 |  | 2023 |  | 2024
In MW | 590 |  | 714 |  | 710 |  | —
As a percentage of total net coal and nuclear capacity(b) | 13% |  | 16% |  | 16% |  | —%

(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 with Midwest Generation and NRG's assets that have project level financing
Capital Expenditures
The following tables and descriptions summarize the Company's capital expenditures for maintenance, environmental and growth investments for the three months ended March 31, 2021, and the estimated capital expenditures forecast for the remainder of 2021.

(In millions) | Maintenance |  | Environmental |  | Growth Investments(a) |  | Total
Texas | $ | (35) |  |  | $ | (1) |  |  | $ | (6) |  |  | $ | (42) |
East | (6) |  |  | — |  |  | (5) |  |  | (11) |
West/Services/Other | (6) |  |  | — |  |  | — |  |  | (6) |
Corporate | (1) |  |  | — |  |  | (3) |  |  | (4) |
Total cash capital expenditures for the three months ended March 31,2021 | (48) |  |  | (1) |  |  | (14) |  |  | (63) |
Investments | — |  |  | — |  |  | (7) |  |  | (7) |
Total capital expenditures and investments | (48) |  |  | (1) |  |  | (21) |  |  | (70) |
Estimated capital expenditures and investments for the remainder of 2021 | $ | (146) |  |  | $ | (6) |  |  | $ | (141) |  |  | $ | (293) |

(a) Includes other investments, acquisitions, digital NRG and integration.
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Growth investments in East for the three months ended March 31, 2021 include the Astoria generating facility, for which the Company has proposed to replace the existing units with a single, new state-of-the-art Simple Cycle Combustion Turbine having a total generating capacity of 437 MW. The Company is working to obtain the permits and regulatory approvals necessary to commence construction of the project. NRG is targeting 2023 for commercial operation. Additionally, included in Investments are expenditures for Encina site improvements classified as ARO payments. Demolition is underway and is expected to be completed in the first half of 2022. The Company expects to begin marketing the site in 2021.
Environmental Capital Expenditures
NRG estimates that environmental capital expenditures from 2021 through 2025 required to comply with environmental laws will be approximately $63 million.
Common Stock Dividends
During the first quarter of 2021, NRG increased the annual dividend to $1.30 from $1.20 per share and expects to target an annual dividend growth rate of 7-9% per share in subsequent years. A quarterly dividend of $0.325 per share was paid on the Company's common stock during the three months ended March 31, 2021. On April 19, 2021, NRG declared a quarterly dividend on the Company's common stock of $0.325 per share, payable on May 17, 2021 to stockholders of record as of May 3, 2021.
Cash Flow Discussion
The following table reflects the changes in cash flows for the comparative three month periods:

| Three months ended March 31, |  |
(In millions) | 2021 |  | 2020 |  | Change
Net Cash (Used)/Provided by Operating Activities | $ | (917) |  |  | $ | 208 |  |  | $ | (1,125) |
Net Cash Used by Investing Activities | (3,364) |  |  | (68) |  |  | (3,296) |
Net Cash Provided by Financing Activities | 924 |  |  | 293 |  |  | 631 |

Net Cash (Used)/Provided by Operating Activities
Changes to net cash (used)/provided by operating activities were driven by:

| (In millions)
Increase in accounts receivable primarily from the impact of Winter Storm Uri | $ | (1,062) |
Decrease in operating income adjusted for other non-cash items | (373) |
Increase in accounts payable primarily due to power, fuel and bilateral settlements as a result of Winter Storm Uri as well as increased customer counts primarily due to the acquisition of Direct Energy | 195 |
Increase primarily due to lower volumes of natural gas inventory in storage and increased oil consumption due to weather | 59 |
Increase in other working capital primarily due to an increase in deferred revenues due to Winter Storm Uri and increased accrued payroll due to the acquisition of Direct Energy, partially offset by an increase in purchases of renewable energy credits primarily due to the acquisition of Direct Energy. | 64 |
Changes in cash collateral in support of risk management activities due to change in commodity prices | (8) |
| $ | (1,125) |

Net Cash Used by Investing Activities
Changes to net cash (used)/provided by investing activities were driven by:

| (In millions)
Increase in cash paid for acquisitions for Direct Energy | $ | (3,482) |
Increase in proceeds from sale of assets primarily due to sale of Agua Caliente | 182 |
Decrease in capital expenditures | 3 |
Other | 1 |
| $ | (3,296) |

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Net Cash Provided by Financing Activities
Changes to net cash provided/(used) by financing activities were driven by:

| (In millions)
Increase in proceeds from Revolving Credit Facility and Receivables Securitization Facilities | $ | 273 |
Increase in net receipts from settlement of acquired derivatives | 193 |
Decrease in payments for share repurchase activity | 170 |
Increase in payments of dividends to common stockholders | (6) |
Other | 1 |
| $ | 631 |

NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740
For the three months ended March 31, 2021, the Company had domestic pre-tax book loss of $189 million and foreign pre-tax book income of $22 million. As of December 31, 2020, the Company had cumulative domestic Federal NOL carryforwards of $10.1 billion, which will begin expiring in 2031, and cumulative state NOL carryforwards of $5.4 billion for financial statement purposes. NRG also has cumulative foreign NOL carryforwards of $347 million, which do not have an expiration date. In addition to the above NOLs, NRG has a $14 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, and based on current forecasts, NRG anticipates income tax payments, primarily to state and foreign jurisdictions, of up to $60 million in 2021.
As of March 31, 2021, the Company has $23 million of tax-effected uncertain federal and state tax benefits, for which the Company has recorded a non-current tax liability (inclusive of accrued interest) until final resolution is reached with the related taxing authority.
The Company is no longer subject to U.S. federal income tax examinations for years prior to 2017. With few exceptions, state and local income tax examinations are no longer open for years prior to 2012.
Deferred tax assets and valuation allowance
Net deferred tax balance – As of March 31, 2021 and December 31, 2020, NRG recorded a net deferred tax asset, excluding valuation allowance, of $2.9 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 March 31, 2021 as discussed below.
NOL Carryforwards – As of March 31, 2021, the Company had a tax-effected cumulative U.S. NOLs consisting of carryforwards for federal and state income tax purposes of $2.1 billion and $456 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 $102 million with no expiration date.
Valuation Allowance – As of March 31, 2021 and December 31, 2020, the Company’s tax-effected valuation allowance was $266 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.
Off-Balance Sheet Arrangements
Obligations under Certain Guarantee Contracts
NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate market transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications.
The Company disclosed its Guarantees in Note 28, Guarantees, to the Company's 2020 Form 10-K. As of March 31, 2021, NRG and its consolidated subsidiaries were contingently obligated for a total of $2.8 billion under letters of credit and surety bonds, compared to $1.2 billion as of December 31, 2020. The increase is primarily due to the acquisition of Direct Energy in January 2021. 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.
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Retained or Contingent Interests
NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity
Variable interest in equity investments — As of March 31, 2021, NRG has investments in energy and energy-related entities that are accounted for under the equity method of accounting. NRG’s investment in Ivanpah is a variable interest entity for which NRG is not the primary beneficiary. See also Note 10, Investments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs.
NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $567 million as of March 31, 2021. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Note 15, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Company's 2020 Form 10-K.
Contractual Obligations and Market Commitments
NRG has a variety of contractual obligations and other market commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs, as disclosed in the Company's 2020 Form 10-K. See also Note 9, Long-term Debt and Finance Leases, and Note 16, Commitments and Contingencies, to this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and market commitments that occurred during the three months ended March 31, 2021.
Guarantor Financial Information
As of March 31, 2021, the Company had outstanding $5.9 billion of Senior Notes and Convertible Senior Notes due 2026 to 2048, outstanding $2.5 billion of Senior Secured First Lien Notes due from 2024 to 2029 and outstanding $466 million of tax-exempt bonds as shown in Note 9, Long-term Debt and Finance Leases. These Senior Notes, Senior Secured First Lien Notes and tax-exempt bonds 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:

(In millions) | For the Year Ended March 31, 2021(a)
Operating revenues | $ | 7,220 |
Operating income | (46) |
Total other expense | (100) |
Income from Continuing Operations | (146) |
Net Income | (57) |

(a)Intercompany transactions with Non-Guarantors include operating revenue of $7 million, cost of operations of $(53) million and selling, general and administrative of $23 million
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The following table presents the summarized balance sheet information:

(In millions) | March 31, 2021
Current assets(a) | $ | 5,788 |
Property, plant and equipment, net | 1,361 |
Non-current assets | 10,966 |
Current liabilities(a) | 5,558 |
Non-current liabilities | 11,566 |

(a)Includes intercompany receivables of $404 million and intercompany payables of $47 million due from Non-Guarantors
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 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.
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 March 31, 2021, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at March 31, 2021. For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Note 5, Fair Value of Financial Instruments.

Derivative Activity (Losses)/Gains | (In millions)
Fair Value of Contracts as of December 31, 2020 | $ | (63) |
Contracts realized or otherwise settled during the period | 150 |
Direct contracts acquired during the period | (283) |
Changes in fair value | 580 |
Fair Value of Contracts as of March 31, 2021 | $ | 384 |

| Fair Value of Contracts as of March 31, 2021
(In millions) | Maturity
Fair value hierarchy (Losses)/Gains | 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 | $ | — |  |  | $ | (11) |  |  | $ | — |  |  | $ | 1 |  |  | $ | (10) |
Level 2 | 179 |  |  | 52 |  |  | 10 |  |  | (6) |  |  | 235 |
Level 3 | 31 |  |  | 27 |  |  | 30 |  |  | 71 |  |  | 159 |
Total | $ | 210 |  |  | $ | 68 |  |  | $ | 40 |  |  | $ | 66 |  |  | $ | 384 |

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 3, Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk, to this Form 10-Q, 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 asset and liability position is a better indicator of NRG's hedging activity. As of March 31, 2021, NRG's net derivative asset was $384 million, an increase to total fair value of $447 million as compared to December 31, 2020. This increase was primarily driven by gains in fair value and roll-off of trades that settled during the period, partially offset by Direct Energy contracts acquired during the period.
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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 $1.309 billion in the net value of derivatives as of March 31, 2021.
The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in a decrease of approximately $1.337 billion in the net value of derivatives as of March 31, 2021.
Critical Accounting Policies and Estimates
NRG's discussion and analysis of the financial condition and results of operations are based upon the condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and the fair value of certain assets and liabilities. These judgments could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies has not changed.
On an ongoing basis, NRG evaluates these estimates, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company's estimates. Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the information that gives rise to the revision becomes known.
The Company identifies its critical accounting policies as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain. NRG's critical accounting policies include derivative instruments, income taxes and valuation allowance for deferred tax assets, impairment of long-lived assets and investments, goodwill and other intangible assets, and contingencies.
The Company's significant accounting policies are outlined in Note 2, Summary of Significant Accounting Policies, of this Form 10-Q, and in Note 2, Summary of Significant Accounting Policies, under Part IV, Item 15 of the Company's 2020 Form 10-K. The Company's critical accounting estimates are described in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in the Company's 2020 Form 10-K. There have been no material changes to the Company's critical accounting policies and estimates since the 2020 Form 10-K.
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ITEM 3 — 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 merchant power generation or with existing or forecasted financial or commodity transactions. The types of market risks the Company is exposed to are commodity price risk, liquidity risk, credit risk, interest rate risk and currency exchange risk. The following disclosures about market risk provide an update to, and should be read in conjunction with, Item 7A, Quantitative and Qualitative Disclosures About Market Risk, of the Company's 2020 Form 10-K.
Commodity Price Risk
Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities and correlations between various commodities, such as natural gas, electricity, coal, oil and emissions credits. NRG manages the commodity price risk of the Company's merchant generation operations and load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricity and fuel. 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 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 three months ending March 31, 2021 and 2020:

(In millions) | 2021 |  | 2020
VaR as of March 31,(a) | $ | 30 |  |  | $ | 29 |
Three months ended March 31, |  |  |
Average(b) | $ | 31 |  |  | $ | 27 |
Maximum(b) | 36 |  |  | 47 |
Minimum(b) | 25 |  |  | 22 |

(a) Calculation includes entire NRG portfolio as of March 31, 2021
(b) Calculation is based on NRG generation assets and load obligations excluding the acquisition of Direct Energy assets and load obligations
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 $94 million, as of March 31, 2021, primarily driven by asset-backed and hedging transactions. The increase in the VaR for derivative financial instruments was primarily due to the acquisition of Direct Energy.
Liquidity Risk
Liquidity risk arises from the general funding needs of the Company's activities and in the management of the Company's assets and liabilities. The Company is currently exposed to additional collateral posting if natural gas prices decline, primarily due to the long natural gas equivalent position at various exchanges used to hedge NRG's retail supply load obligations.
Based on a sensitivity analysis for power and gas positions under marginable contracts as of March 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 $1,009 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 $345 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of March 31, 2021.
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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. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply arrangements, and retail customer credit risk through its retail load activities. See Note 5, Fair Value of Financial Instruments, to this Form 10-Q for discussions regarding counterparty credit risk and retail customer credit risk, and Note 7, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-Q for discussion regarding credit risk contingent features.
Interest Rate Risk
As of March 31, 2021, the fair value and related carrying value of the Company's debt was $10 billion and $9.6 billion respectively. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt as of March 31, 2021 by $718 million.
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 March 31, 2021, NRG is exposed to changes in foreign currency 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 $158 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 10% depreciation or appreciation in major currencies relative to the U.S. dollar as of March 31, 2021 would not have resulted in a material difference within the Consolidated Statement of Operations.
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ITEM 4 — CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
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 Quarterly Report on Form 10-Q.
Changes in Internal Control over Financial Reporting
There were no changes in NRG's internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the quarter ended March 31, 2021 that materially affected, or are reasonably likely to materially affect, NRG's internal control over financial reporting.
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PART II — OTHER INFORMATION
ITEM 1 — LEGAL PROCEEDINGS
For a discussion of material legal proceedings in which NRG was involved through March 31, 2021, see Note 16, Commitments and Contingencies, to this Form 10-Q.
ITEM 1A — RISK FACTORS
During the three months ended March 31, 2021, there were no material changes to the Risk Factors disclosed in Part I, Item 1A, Risk Factors, of the Company's 2020 Form 10-K.
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
During the quarter ended March 31, 2021, no purchases of NRG's common stock were made by or on behalf of NRG or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Exchange Act).
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4 — MINE SAFETY DISCLOSURES
There have been no events that are required to be reported under this Item.
ITEM 5 — OTHER INFORMATION
None.
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ITEM 6 — EXHIBITS

Number |  | Description |  | Method of Filing
2† |  | Purchase and Sale Agreement dated as of February 28, 2021 by and between NRG Energy, Inc., and Generation Bridge Acquisition, LLC, as a Purchaser |  | Filed herewith
4.1 |  | 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. |  | Filed herewith.
4.2 |  | 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. |  | Filed herewith.
4.3 |  | Supplemental Indenture (additional Subsidiary Guarantees-7.250% Senior Notes due 2026) dated January 5, 2021, among NRG Energy, Inc., each of its guarantor subsidiaries, and Delaware Trust Company as trustee. |  | Filed herewith.
4.4 |  | 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. |  | Filed herewith.
4.5 |  | 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. |  | Filed herewith.
4.6 |  | 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. |  | Filed herewith.
4.7 |  | 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. |  | Filed herewith.
4.8 |  | 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. |  | Filed herewith.
4.9 |  | 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. |  | Filed herewith.
22.1 |  | List of Guarantor Subsidiaries |  | Filed herewith.
31.1 |  | Rule 13a-14(a)/15d-14(a) certification of Mauricio Gutierrez. |  | Filed herewith.
31.2 |  | Rule 13a-14(a)/15d-14(a) certification of Gaëtan Frotté. |  | Filed herewith.
31.3 |  | Rule 13a-14(a)/15d-14(a) certification of David Callen. |  | Filed herewith.
32 |  | Section 1350 Certification. |  | Furnished herewith.
101 INS |  | Inline XBRL Instance Document. |  | The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document.
101 SCH |  | Inline XBRL Taxonomy Extension Schema. |  | Filed herewith.
101 CAL |  | Inline XBRL Taxonomy Extension Calculation Linkbase. |  | Filed herewith.
101 DEF |  | Inline XBRL Taxonomy Extension Definition Linkbase. |  | Filed herewith.
101 LAB |  | Inline XBRL Taxonomy Extension Label Linkbase. |  | Filed herewith.
101 PRE |  | Inline XBRL Taxonomy Extension Presentation Linkbase. |  | Filed herewith.
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). |  | Filed herewith.

† |  | 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 “[***]”.

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

| NRG ENERGY, INC. (Registrant) |
| /s/ MAURICIO GUTIERREZ |
| Mauricio Gutierrez |
| Chief Executive Officer (Principal Executive Officer) |
| /s/ GAËTAN FROTTÉ |
| Gaëtan Frotté |
| Interim Chief Financial Officer (Principal Financial Officer) |
| /s/ DAVID CALLEN |
| David Callen |
Date: May 6, 2021 | Chief Accounting Officer (Principal Accounting Officer) |

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