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: | June 30, 2020March 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.) |
| | | | | | | | | | | |
804 Carnegie Center,910 Louisiana Street | PrincetonHouston | New JerseyTexas | 0854077002 |
| (Address of principal executive offices) | | | (Zip Code) |
(609) 524-4500713) 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 AugustMay 6, 2020,2021, there were 244,137,848244,753,963 shares of common stock outstanding, par value $0.01 per share.
TABLE OF CONTENTS
Index
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, 20192020 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;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;
•NRG's ability to successfully integrate, realize cost savings and manage any acquired businesses;
•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 the indentures governing NRG's Senior Notes, Senior Secured Notes and Senior Credit Facility,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 develop and innovate new products, as retail and wholesale markets continue to change and evolve;
•NRG's ability to implement its strategy of finding ways to meet the challenges of climate change, clean air and protecting natural resources, while taking advantage of business opportunities;
•NRG's ability to increase cash from operations through operational and 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;
•NRG's ability to achieve the expected benefits of its Transformation Plan; and
•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.
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
| | | | | | | | |
20192020 Form 10-K | | NRG’s Annual Report on Form 10-K for the year ended December 31, 2019 |
2023 Term Loan Facility | | The Company's term loan facility due 2023, a component of the Senior Credit Facility, which was repaid during the second quarter of 20192020 |
| 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 ownsowned 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 |
Bankruptcy Code | | Chapter 11 of Title 11 the U.S. Bankruptcy Code |
| BTU | | British Thermal Unit |
Business Solutions | | NRG'sNRG Business, which serves medium and large business solutions group, which includes demand response, commodity sales, energy efficiency and energy management servicescustomers |
| CAA | | Clean Air Act |
| CAISO | | California Independent System Operator |
California Bankruptcy Court | | United States Bankruptcy Court for the Northern District of California, San Francisco Division |
| CARES Act | | Coronavirus Aid, Relief, and Economic Security Act |
Carlsbad | | Carlsbad Energy Center, a 528 MW natural gas-fired project located in Carlsbad, CA of 2020 |
| CCR | | Coal Combustion Residuals |
| CDD | | Cooling Degree Day |
| | |
| CFTC | | U.S. Commodity Futures Trading Commission |
| | |
C&I | | Commercial industrial and governmental/institutional |
| Centrica | | Centrica plc |
| CES | | Clean Energy Standard |
| Cleco | | Cleco Corporate Holdings LLC |
CO2 | | Carbon Dioxide |
| ComEd | | Commonwealth Edison |
| Company | | NRG Energy, Inc. |
| Convertible Senior Notes | | As of June 30, 2020,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 |
Distributed Solar | | Solar power projects that primarily sell power to customers for usage on site, or are interconnected to sell power into a local distribution grid |
| 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 |
ESCO | | Energy Service Companies |
| 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. |
GenOn | | GenOn Energy, Inc. |
GenOn Entities | | GenOn and certain of its wholly owned subsidiaries, including GenOn Americas Generation, that filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Texas Bankruptcy Court on June 14, 2017 |
| GHG | | Greenhouse Gas |
GIPGW | | Global Infrastructure PartnersGigawatts |
| | | | | | | | |
| 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 |
HSR Act | | Hart-Scott-Rodino Act |
| 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 |
MWe | | Megawatt equivalent |
| 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 |
NJBPU | | New Jersey Board of Public Utilities |
| 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. |
| | |
| | |
NRG Yield, Inc. | | NRG Yield, Inc., which changed its name to Clearway Energy, Inc. following the sale by NRG of NRG Yield and the Renewables Platform to GIP |
| | | | | | | | |
| 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) |
ORDC | | Operating Reserve Demand Curve |
| Petra Nova | | Petra Nova Parish Holdings, LLC which is 50% owned by NRG and which owns and operates a 240 MWe carbon capture system and a 78 MW cogeneration facility, and owns an equity interest in an oilfield |
PG&E | | PG&E Corporation (NYSE: PCG) and its primary operating subsidiary, Pacific Gas and Electric Company |
| 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 |
| | | | | | | | |
| 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 |
Reliant Energy | | Reliant Energy Retail Services, LLC |
| | |
RenewablesReceivables Securitization Facilities | | Consists ofCollectively, the following projects in which NRG has an ownership interest: Agua Caliente, Ivanpah,Receivables Facility and solar generating stations located at various NFL Stadiums |
Renewables Platform | | The renewable operating and development platform sold by NRG to GIP with NRG's interest in NRG Yield, Inc.the Repurchase Facility |
| Revolving Credit Facility | | The Company's $2.6$3.7 billion revolving credit facility a component of the Senior 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 Credit Facility | | NRG's senior secured credit facility, comprised of the Revolving Credit Facility and the 2023 Term Loan Facility. The 2023 Term Loan Facility was repaid in the second quarter of 2019 |
Senior Notes | | As of June 30, 2020,March 31, 2021, NRG's $3.8$5.3 billion outstanding unsecured senior notes consisting of $1.0 billion of the 7.25% senior notes due 2026, $1.23$1.2 billion of the 6.625% senior notes due 2027, $821 million of 5.75% senior notes due 2028, and $733 million of the 5.250%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 June 30, 2020,March 31, 2021, NRG’s $1.1$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 |
SO2 | | 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 |
Transformation Plan | | NRG's three-year plan announced in 2017, which includes targets related to operations and excellence, portfolio optimization, and capital structure and allocation enhancement |
TWCC | | Texas Westmoreland Coal Co. |
| 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 |
ZECsWinter Storm Uri | | Zero Emissions CreditsA major winter and ice storm that had widespread impacts across North America occurring in February 2021 |
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 June 30, | | | | Six months ended June 30, | | |
| (In millions, except for per share amounts) | 2020 | | 2019 | | 2020 | | 2019 |
| Operating Revenues | | | | | | | |
| Total operating revenues | $ | 2,238 | | | $ | 2,465 | | | $ | 4,257 | | | $ | 4,630 | |
| Operating Costs and Expenses | | | | | | | |
| Cost of operations | 1,434 | | | 1,845 | | | 2,891 | | | 3,496 | |
| Depreciation and amortization | 110 | | | 85 | | | 219 | | | 170 | |
| Impairment losses | — | | | 1 | | | — | | | 1 | |
| Selling, general and administrative costs | 208 | | | 211 | | | 417 | | | 405 | |
| Reorganization costs | — | | | 2 | | | 3 | | | 15 | |
| Development costs | 2 | | | 2 | | | 5 | | | 4 | |
| Total operating costs and expenses | 1,754 | | | 2,146 | | | 3,535 | | | 4,091 | |
| | | | | | | |
| Gain on sale of assets | — | | | 1 | | | 6 | | | 2 | |
| Operating Income | 484 | | | 320 | | | 728 | | | 541 | |
| Other Income/(Expense) | | | | | | | |
| Equity in earnings/(losses) of unconsolidated affiliates | 12 | | | — | | | 1 | | | (21) | |
| Impairment losses on investments | — | | | — | | | (18) | | | — | |
| Other income, net | 14 | | | 20 | | | 41 | | | 32 | |
| Loss on debt extinguishment, net | — | | | (47) | | | (1) | | | (47) | |
| Interest expense | (96) | | | (105) | | | (193) | | | (219) | |
| Total other expense | (70) | | | (132) | | | (170) | | | (255) | |
| Income from Continuing Operations Before Income Taxes | 414 | | | 188 | | | 558 | | | 286 | |
| Income tax expense/(benefit) | 101 | | | (1) | | | 124 | | | 3 | |
| Income from Continuing Operations | 313 | | | 189 | | | 434 | | | 283 | |
| Income from discontinued operations, net of income tax | — | | | 13 | | | — | | | 401 | |
| Net Income | 313 | | | 202 | | | 434 | | | 684 | |
| Less: Net income attributable to redeemable noncontrolling interests | — | | | 1 | | | — | | | 1 | |
| Net Income Attributable to NRG Energy, Inc. | $ | 313 | | | $ | 201 | | | $ | 434 | | | $ | 683 | |
| Earnings per Share | | | | | | | |
| Weighted average number of common shares outstanding — basic | 245 | | | 265 | | | 246 | | | 272 | |
| Income from continuing operations per weighted average common share — basic | $ | 1.28 | | | $ | 0.71 | | | $ | 1.76 | | | $ | 1.04 | |
| Income from discontinued operations per weighted average common share — basic | $ | — | | | $ | 0.05 | | | $ | — | | | $ | 1.47 | |
| Earnings per Weighted Average Common Share — Basic | $ | 1.28 | | | $ | 0.76 | | | $ | 1.76 | | | $ | 2.51 | |
| Weighted average number of common shares outstanding — diluted | 246 | | | 267 | | | 247 | | | 274 | |
| Income from continuing operations per weighted average common share — diluted | $ | 1.27 | | | $ | 0.70 | | | $ | 1.76 | | | $ | 1.03 | |
| Income from discontinued operations per weighted average common share — diluted | $ | — | | | $ | 0.05 | | | $ | — | | | $ | 1.46 | |
| Earnings per Weighted Average Common Share — Diluted | $ | 1.27 | | | $ | 0.75 | | | $ | 1.76 | | | $ | 2.49 | |
| | | | | | | | | | | | | | | |
| 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 | 0 | | | (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.
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.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOMEBALANCE SHEETS
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | |
| Three months ended June 30, | | | | Six months ended June 30, | | |
| (In millions) | 2020 | | 2019 | | 2020 | | 2019 |
| Net Income | $ | 313 | | | $ | 202 | | | $ | 434 | | | $ | 684 | |
| Other Comprehensive Income/(Loss) | | | | | | | |
| | | | | | | |
| Foreign currency translation adjustments | 13 | | | (1) | | | (2) | | | — | |
| Available-for-sale securities | — | | | 1 | | | — | | | 1 | |
| Defined benefit plans | — | | | (3) | | | — | | | (6) | |
| Other comprehensive income/(loss) | 13 | | | (3) | | | (2) | | | (5) | |
| Comprehensive Income | 326 | | | 199 | | | 432 | | | 679 | |
| Less: Comprehensive income attributable to redeemable noncontrolling interest | — | | | 1 | | | — | | | 1 | |
| Comprehensive Income Attributable to NRG Energy, Inc. | $ | 326 | | | $ | 198 | | | $ | 432 | | | $ | 678 | |
| | | | | | | | | | | |
| 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 | 0 | | 0 |
| 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.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETSSTATEMENTS OF CASH FLOWS
| | | | | | | | | | | |
| June 30, 2020 | | December 31, 2019 |
| (In millions, except share data) | (Unaudited) | | (Audited) |
| ASSETS | | | |
| Current Assets | | | |
| Cash and cash equivalents | $ | 418 | | | $ | 345 | |
| Funds deposited by counterparties | 36 | | | 32 | |
| Restricted cash | 8 | | | 8 | |
| Accounts receivable, net | 1,015 | | | 1,025 | |
| Inventory | 388 | | | 383 | |
| Derivative instruments | 791 | | | 860 | |
| Cash collateral paid in support of energy risk management activities | 136 | | | 190 | |
| | | |
| Prepayments and other current assets | 284 | | | 245 | |
| | | |
| | | |
| Total current assets | 3,076 | | | 3,088 | |
| Property, plant and equipment, net | 2,533 | | | 2,593 | |
| Other Assets | | | |
| Equity investments in affiliates | 372 | | | 388 | |
| | | |
| Operating lease right-of-use assets, net | 429 | | | 464 | |
| Goodwill | 579 | | | 579 | |
| Intangible assets, net | 733 | | | 789 | |
| Nuclear decommissioning trust fund | 794 | | | 794 | |
| Derivative instruments | 439 | | | 310 | |
| Deferred income taxes | 3,170 | | | 3,286 | |
| Other non-current assets | 212 | | | 240 | |
| | | |
| | | |
| Total other assets | 6,728 | | | 6,850 | |
| Total Assets | $ | 12,337 | | | $ | 12,531 | |
| | | |
| LIABILITIES AND STOCKHOLDERS' EQUITY | | | |
| Current Liabilities | | | |
| Current portion of long-term debt | $ | 7 | | | $ | 88 | |
| Current portion of operating lease liabilities | 69 | | | 73 | |
| Accounts payable | 736 | | | 722 | |
| | | |
| Derivative instruments | 728 | | | 781 | |
| Cash collateral received in support of energy risk management activities | 36 | | | 32 | |
| Accrued expenses and other current liabilities | 581 | | | 663 | |
| | | |
| | | |
| | | |
| Total current liabilities | 2,157 | | | 2,359 | |
| Other Liabilities | | | |
| Long-term debt | 5,810 | | | 5,803 | |
| Non-current operating lease liabilities | 458 | | | 483 | |
| Nuclear decommissioning reserve | 307 | | | 298 | |
| Nuclear decommissioning trust liability | 478 | | | 487 | |
| | | |
| Derivative instruments | 299 | | | 322 | |
| Deferred income taxes | 17 | | | 17 | |
| Other non-current liabilities | 1,061 | | | 1,084 | |
| | | |
| | | |
| Total other liabilities | 8,430 | | | 8,494 | |
| Total Liabilities | 10,587 | | | 10,853 | |
| Redeemable noncontrolling interest in subsidiaries | — | | | 20 | |
| Commitments and Contingencies | | | |
| Stockholders' Equity | | | |
| Common stock; $0.01 par value; 500,000,000 shares authorized; 423,031,777 and 421,890,790 shares issued and 244,137,848 and 248,996,189 shares outstanding at June 30, 2020 and December 31, 2019, respectively | 4 | | | 4 | |
| Additional paid-in-capital | 8,505 | | | 8,501 | |
| Accumulated deficit | (1,331) | | | (1,616) | |
| Treasury stock, at cost - 178,893,929 and 172,894,601 shares at June 30, 2020 and December 31, 2019, respectively | (5,234) | | | (5,039) | |
| Accumulated other comprehensive loss | (194) | | | (192) | |
| | | |
| Total Stockholders' Equity | 1,750 | | | 1,658 | |
| Total Liabilities and Stockholders' Equity | $ | 12,337 | | | $ | 12,531 | |
| | | | | | | | | | | |
| 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 | 0 | | | 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) | | | 0 | |
| 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) | | | 0 | |
| Proceeds from issuance of common stock | 1 | | | 0 | |
| Repayments of long-term debt and finance leases | (1) | | | (60) | |
| Proceeds from issuance of long-term debt | 0 | | | 59 | |
| Purchase of and distributions to noncontrolling interests from subsidiaries | 0 | | | (2) | |
| | | |
| | | |
| Cash provided by financing activities | 924 | | | 293 | |
| | | |
| | | |
| Effect of exchange rate changes on cash and cash equivalents | 1 | | | 0 | |
| | | |
| 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.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWSSTOCKHOLDERS' EQUITY
(Unaudited)
| | | | | | | | | | | |
| Six months ended June 30, | | |
| (In millions) | 2020 | | 2019 |
| Cash Flows from Operating Activities | | | |
| Net Income | $ | 434 | | | $ | 684 | |
| Income from discontinued operations, net of income tax | — | | | 401 | |
| Income from continuing operations | 434 | | | 283 | |
| Adjustments to reconcile net income to cash provided by operating activities: | | | |
| Distributions from and equity in (earnings)/losses of unconsolidated affiliates | 7 | | | 22 | |
| Depreciation and amortization | 219 | | | 170 | |
| Accretion of asset retirement obligations | 18 | | | 14 | |
| Provision for credit losses | 48 | | | 52 | |
| Amortization of nuclear fuel | 25 | | | 27 | |
| Amortization of financing costs and debt discount/premiums | 12 | | | 13 | |
| Loss on debt extinguishment, net | 1 | | | 47 | |
| Amortization of emissions allowances and energy credits | 33 | | | 14 | |
| Amortization of unearned equity compensation | 12 | | | 10 | |
| (Gain)/loss on sale of assets and disposal of assets | (15) | | | 1 | |
| | | |
| Impairment losses | 18 | | | 1 | |
| Changes in derivative instruments | (131) | | | (22) | |
| Changes in deferred income taxes and liability for uncertain tax benefits | 116 | | | (5) | |
| Changes in collateral deposits in support of energy risk management activities | 58 | | | 125 | |
| Changes in nuclear decommissioning trust liability | 36 | | | 17 | |
| | | |
| | | |
| Changes in other working capital | (199) | | | (352) | |
| Cash provided by continuing operations | 692 | | | 417 | |
| Cash provided by discontinued operations | — | | | 8 | |
| Net Cash Provided by Operating Activities | 692 | | | 425 | |
| Cash Flows from Investing Activities | | | |
| Payments for acquisitions of businesses | (5) | | | (21) | |
| Capital expenditures | (116) | | | (107) | |
| | | |
| Net purchases of emission allowances | (4) | | | (1) | |
| Investments in nuclear decommissioning trust fund securities | (257) | | | (209) | |
| Proceeds from the sale of nuclear decommissioning trust fund securities | 220 | | | 191 | |
| Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees | 15 | | | 1,289 | |
| | | |
| Net distributions from investments in unconsolidated affiliates | 2 | | | 7 | |
| Contributions to discontinued operations | — | | | (44) | |
| | | |
| Cash (used)/provided by continuing operations | (145) | | | 1,105 | |
| Cash used by discontinued operations | — | | | (2) | |
| Net Cash (Used)/Provided by Investing Activities | (145) | | | 1,103 | |
| Cash Flows from Financing Activities | | | |
| Payments of dividends to common stockholders | (148) | | | (16) | |
| Payments for share repurchase activity | (229) | | | (1,075) | |
| | | |
| Payments for debt extinguishment costs | — | | | (24) | |
| Purchase of and distributions to noncontrolling interests from subsidiaries | (2) | | | (1) | |
| Proceeds from issuance of common stock | 1 | | | 2 | |
| Proceeds from issuance of long-term debt | 59 | | | 1,833 | |
| Payment of debt issuance costs | (1) | | | (33) | |
| Repayments of long-term debt | (61) | | | (2,485) | |
| Net repayment of Revolving Credit Facility | (83) | | | — | |
| | | |
| Other | (5) | | | — | |
| Cash used by continuing operations | (469) | | | (1,799) | |
| Cash provided by discontinued operations | — | | | 43 | |
| Net Cash Used by Financing Activities | (469) | | | (1,756) | |
| Effect of exchange rate changes on cash and cash equivalents | (1) | | | — | |
| Change in Cash from discontinued operations | — | | | 49 | |
| Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash | 77 | | | (277) | |
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period | 385 | | | 613 | |
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period | $ | 462 | | | $ | 336 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (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) | |
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| Balance at March 31, 2021 | | | $ | 4 | | | $ | 8,513 | | | $ | (1,565) | | | $ | (5,232) | | | $ | (203) | | | | | $ | 1,517 | |
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| (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) | |
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Common stock dividends and dividend equivalents declared(b) | | | | | | | (75) | | | | | | | | | (75) | |
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| Balance at March 31, 2020 | | | $ | 4 | | | $ | 8,498 | | | $ | (1,570) | | | $ | (5,189) | | | $ | (207) | | | | | $ | 1,536 | |
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(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.
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, 2019 | | | $ | 4 | | | $ | 8,501 | | | $ | (1,616) | | | $ | (5,039) | | | $ | (192) | | | | | $ | 1,658 | |
| Net income attributable to NRG Energy, Inc. | | | | | | | 121 | | | | | | | | | 121 | |
| Other comprehensive loss | | | | | | | | | | | (15) | | | | | (15) | |
| Repurchase of partners' equity interest in VIE | | | | | 18 | | | | | | | | | | | 18 | |
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| Share repurchases | | | | | | | | | (150) | | | | | | | (150) | |
| Equity-based awards activity, net | | | | | (21) | | | | | | | | | | | (21) | |
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Common stock dividends and dividend equivalents declared(a) | | | | | | | (75) | | | | | | | | | (75) | |
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| Balance at March 31, 2020 | | | $ | 4 | | | $ | 8,498 | | | $ | (1,570) | | | $ | (5,189) | | | $ | (207) | | | | | $ | 1,536 | |
| Net income attributable to NRG Energy, Inc. | | | | | | | 313 | | | | | | | | | 313 | |
| Other comprehensive income | | | | | | | | | | | 13 | | | | | 13 | |
| Shares reissuance for ESPP | | | | | | | | | 2 | | | | | | | 2 | |
| Share repurchases | | | | | | | | | (47) | | | | | | | (47) | |
| Equity-based awards activity, net | | | | | 6 | | | | | | | | | | | 6 | |
| Issuance of common stock | | | | | 1 | | | | | | | | | | | 1 | |
Common stock dividends and dividend equivalents declared(a) | | | | | | | (74) | | | | | | | | | (74) | |
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| Balance at June 30, 2020 | | | $ | 4 | | | $ | 8,505 | | | $ | (1,331) | | | $ | (5,234) | | | $ | (194) | | | | | $ | 1,750 | |
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| (In millions) | | | Common
Stock | | Additional
Paid-In
Capital | | Accumulated Deficit | | Treasury
Stock | | Accumulated
Other
Comprehensive
Loss | | | | Total
Stock-holders'
Equity |
| Balance at December 31, 2018 | | | $ | 4 | | | $ | 8,510 | | | $ | (6,022) | | | $ | (3,632) | | | $ | (94) | | | | | $ | (1,234) | |
| Net income attributable to NRG Energy, Inc. | | | | | | | 482 | | | | | | | | | 482 | |
| Other comprehensive loss | | | | | | | | | | | (2) | | | | | (2) | |
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| Share repurchases | | | | | (10) | | | | | (739) | | | | | | | (749) | |
| Equity-based awards activity, net | | | | | (32) | | | | | | | | | | | (32) | |
| Issuance of common stock | | | | | 5 | | | | | | | | | | | 5 | |
Common stock dividends and dividend equivalents declared(a) | | | | | | | (8) | | | | | | | | | (8) | |
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| Balance at March 31, 2019 | | | $ | 4 | | | $ | 8,473 | | | $ | (5,548) | | | $ | (4,371) | | | $ | (96) | | | | | $ | (1,538) | |
| Net income attributable to NRG Energy, Inc. | | | | | | | 201 | | | | | | | | | 201 | |
| Other comprehensive loss | | | | | | | | | | | (3) | | | | | (3) | |
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| Share repurchases | | | | | 10 | | | | | (315) | | | | | | | (305) | |
| Equity-based awards activity, net | | | | | 5 | | | | | | | | | | | 5 | |
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Common stock dividends and dividend equivalents declared(a) | | | | | | | (8) | | | | | | | | | (8) | |
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| Balance at June 30, 2019 | | | $ | 4 | | | $ | 8,488 | | | $ | (5,355) | | | $ | (4,686) | | | $ | (99) | | | | | $ | (1,648) | |
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(a) Dividends per common share were $0.30 for each of the quarters ended June 30, 2020 and March 31, 2020 and $0.03 for each of the quarters ended June 30, 2019 and March 31, 2019
See accompanying notes to condensed consolidated financial statements.
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 consumerscustomers by producing and selling electricityenergy 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-drivencustomer-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 brand 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 June 30, 2020.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 condensed consolidated financial statements in the Company's 20192020 Form 10-K and the Current Report on Form 8-K filed May 7, 2020, which provides retrospectively revised historical financial information to correspond with the Company's current segment structure.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 June 30, 2020,March 31, 2021, and the results of operations, comprehensive income, cash flows and statements of stockholders' equity for the three and six months ended June 30, 2020March 31, 2021 and 2019.
Segments
As part of perfecting the integrated model, in which the majority of the Company’s generation serves its retail customers, the Company began managing its operations based on the combined results of the retail and wholesale generation businesses with a geographical focus in 2020. As a result, the Company changed its business segments from Retail and Generation to Texas, East and West/Other beginning in the first quarter of 2020. The Company's updated segment structure reflects how management currently makes financial decisions and allocates resources.
The Company's businesses are segregated as follows:
•Texas, which includes all activity related to customer, plant and market operations in Texas;
•East, which includes the remaining activity related to customer operations and all activity related to plant and market operations in the East;
•West/Other, which includes the following assets and activities: (i) all activity related to plant and market operations in the West, (ii) activity related to the Cottonwood power plant that was sold to Cleco on February 4, 2019 and is being leased back until 2025, (iii) the remaining renewables activity, including the Company’s equity method investments in Ivanpah Master Holdings, LLC and Agua Caliente, the remaining Home Solar assets and the NFL stadium solar generating assets, and (iv) activity related to the Company’s equity method investment for the Gladstone power plant in Australia; and
•Corporate activities.
All affected disclosures have been recast to reflect these changes for all periods presented. For further discussion of segment reporting, refer to Note 13, Segment Reporting.
COVID-19
In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the COVID-19 outbreak a national emergency. Electricity was deemed a 'critical and essential business operation' under various state and federal governmental COVID-19 mandates. NRG had activated its Crisis Management Team ("CMT") in January 2020 to proactively manage the Company's response to the impacts of COVID-19.
NRG continues to remain 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 the second quarter of 2020, the Company began to evaluate and implement protocols for return to normal work operations.
The Company continues to maintain certain restrictions on business travel and face-to-face sales channels, remote work practices remain in place and there are enhanced cleaning and hygiene protocols in all of its facilities. In addition, select essential employees and contractors are continuing to report to plant and certain office locations. The Company also continues to require pre-entry screening, including temperature checks, separation of work crews, additional personal protective equipment for employees and contractors when social distancing cannot be maintained, and a ban on all non-essential visitors. The Company has not experienced any material disruptions in its ability to continue its business operations to date.
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) | (In millions) | June 30, 2020 | | December 31, 2019 | (In millions) | March 31, 2021 | | December 31, 2020 | |
| Property, plant and equipment accumulated depreciation | Property, plant and equipment accumulated depreciation | $ | 1,868 | | | $ | 1,752 | | Property, plant and equipment accumulated depreciation | $ | 1,566 | | | $ | 1,936 | | |
| Intangible assets accumulated amortization | Intangible assets accumulated amortization | 1,279 | | | 1,262 | | Intangible assets accumulated amortization | 1,424 | | | 1,357 | | |
Credit Losses
On January 1, 2020, the Company adopted ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, or ASU No. 2016-13, using the modified retrospective approach. Following the adoption of the new standard, the Company’s process of estimating expected credit losses remains materially consistent with its historical practice. Information prior to January 1, 2020, which was previously referred to as the allowance and provision for bad debt, has not been restated and continues to be reported under the accounting standards in effect for that period.
Retail trade receivables are reported on the balance sheet net of the allowance for credit losses. The Company accrues an allowancea 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 and six months ended June 30, 2020:March 31, 2021:
| | (In millions) | (In millions) | Three months ended June 30, 2020 | | Six months ended June 30, 2020 | (In millions) | Three months ended March 31, 2021 | | | Three months ended March 31, 2020 | |
| Beginning balance | Beginning balance | $ | 39 | | | $ | 43 | | Beginning balance | $ | 67 | | | | $ | 43 | | |
| Acquired balance from Direct Energy | | Acquired balance from Direct Energy | 112 | | | | 0 | | |
| Provision for credit losses | Provision for credit losses | 24 | | | 48 | | Provision for credit losses | 611 | | | | 24 | | |
| Write-offs | Write-offs | (20) | | | (52) | | Write-offs | (48) | | | | (32) | | |
| Recoveries collected | Recoveries collected | 4 | | | 8 | | Recoveries collected | 7 | | | | 4 | | |
| Ending balance | Ending balance | $ | 47 | | | $ | 47 | | 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) | June 30, 2020 | | December 31, 2019 | | | | |
| Cash and cash equivalents | $ | 418 | | | $ | 345 | | | | | |
| Funds deposited by counterparties | 36 | | | 32 | | | | | |
| Restricted cash | 8 | | | 8 | | | | | |
| Cash and cash equivalents, funds deposited by counterparties and restricted cash shown in the statement of cash flows | $ | 462 | | | $ | 385 | | | | | |
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| (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.
Pension Plan Contributions
On March 27, 2020, the Senate passed the CARES Act to provide necessary emergency relief related to the COVID-19 pandemic. The CARES Act allows NRG and other pension plan sponsors to postpone 2020 contributions until January 1, 2021. As a result, NRG will consider deferring approximately $47 million in cash contributions previously planned to be made to the Company's pension plans in 2020. NRG’s pension and postretirement benefit plans are further described in Note 15, Benefit Plans and Other Postretirement Benefits, to the Company’s 2019 Form 10-K.
Recent Accounting Developments - Guidance Adopted in 20202021
ASU 2018-172019-12 — — In October 2018,December 2019, the FASB issued ASU No. 2018-17,2019-12, ConsolidationsIncome Taxes (Topic 810)740): Targeted Improvements to Related Party GuidanceSimplifying the Accounting for Variable Interest EntitiesIncome Taxes, , or ASU No. 2018-17,2019-12, to simplify various aspects related to accounting for income taxes. The guidance in responseASU 2019-12 amends the general principles in Topic 740 to stakeholders’ observations that Topic 810, Consolidations, could be improved thereby improving general purpose financial reporting. Specifically,eliminate certain exceptions for recognizing deferred taxes for investment, performing intraperiod allocation and calculating income taxes in interim periods. This ASU No. 2018-17 requires application of the variable interest entity (VIE)also includes guidance to private companies under common controlreduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and considerationallocating taxes to members of indirect interest held through related parties under common control for determining whether fees paid to decision makers and service providers are variable interests. The amendments area consolidated group. ASU 2019-12 is effective for fiscal years beginning after December 15, 2019,2020, and interim periods within those fiscal years. All entities are required to apply the amendments retrospectively. The adoption did not have a material impact on the Company's results of operations, cash flows, or statement of financial position.
ASU 2018-15 — In August 2018, the FASB issued ASU No. 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in Cloud Computing Arrangement That Is a Service Contract, or ASU No. 2018-15. The amendments in ASU No. 2018-15 align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing costs incurred to develop or obtain internal-use software (and hosting arrangement that include an internal-use software license). The amendment also requires the customer to amortize the capitalized implementation costs of a hosting arrangement that is a service contract over the term of the hosting arrangement. The Company adopted the amendments effective January 1, 20202021 using the prospective
approach. The adoption did not have a material impact on the Company's results of operations, cash flows, or statement of financial position.
ASU 2018-13 — In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirement for Fair value Measurement), or ASU No. 2018-13. The amendments in ASU No. 2018-13 eliminate such disclosures as the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy and add new disclosure requirements for Level 3 measurements. ASU No. 2018-13 is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Certain disclosures in ASU No. 2018-13 are required to be applied on a retrospective basis and others on a prospective basis. The Company adopted the amendments effective January 1, 2020. As the amendments contemplates changes in disclosures only, it did not have an impact on the Company's results of operations, cash flows, or statement of financial position.
ASU 2016-13 — In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Statements, or ASU No. 2016-13, which was further amended through various updates issued by the FASB thereafter. The guidance in ASU No. 2016-13 provides a new model for recognizing credit losses on financial assets carried at amortized cost using an estimate of expected credit losses, instead of the "incurred loss" methodology previously required for recognizing credit losses that delayed recognition until it was probable that a loss was incurred. The estimate of expected credit losses is to be based on consideration of past events, current conditions and reasonable and supportable forecasts of future conditions. The Company adopted the standard and its subsequent corresponding updates effective January 1, 2020 using the modified retrospective approach. Results for the reporting periods after January 1, 2020 are presented under Topic 326 while prior period amounts continue to be reported in accordance with previously applicable GAAP. The Company's adoption of Topic 326 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 2019-12 2020-06 — In December 2019,August 2020, the FASB issued ASU No. 2019-12,2020-06, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, 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. 2019-12, to simplify various aspects related to accounting for income taxes.2020-06. The guidance in ASU 2019-122020-06 reduces the number of accounting models for convertible debt instruments and convertible preferred stock. In addition, ASU 2020-06 improves and 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.related earnings per share guidance. 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 2019-12standard is effective for fiscal years beginning after December 15, 2020,2021, and interim periods within those fiscal years,.years. Early adoption is permitted in fiscal years beginning after December 15, 2020, including adoption in an interim period.periods within those fiscal years. The Company is currently in the process of assessing the impact of this guidance on the consolidated financial statements.statements and disclosures related to earnings per share.
Note 3 — Revenue Recognition
Performance Obligations
As of June 30, 2020,March 31, 2021, estimated future fixed fee performance obligations are $314$544 million for the remaining sixnine months of fiscal year 2020,2021, and $620$299 million, $307$51 million, $42$37 million and $8$20 million for the fiscal years 2021, 2022, 2023, 2024 and 2024,2025, 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.non-performance.
Disaggregated Revenues
The following tables represent the Company’s disaggregation of revenue from contracts with customers for the three and six months ended June 30, 2020March 31, 2021 and 2019:2020:
| | | Three months ended June 30, 2020 | | | Three months ended March 31, 2021 |
| (In millions) | (In millions) | Texas | | East | | West/Other | | Corporate/Eliminations | | Total | (In millions) | Texas | | East | | West/Services/Other | | Corporate/Eliminations | | Total |
| Retail revenue: | Retail revenue: | | | | | | | | | | Retail revenue: | | | | | | | | | |
| Mass Market | $ | 1,273 | | | $ | 291 | | | $ | — | | | $ | — | | | $ | 1,564 | | |
| Business Solutions | 248 | | | 20 | | | — | | | — | | | 268 | | |
Home(a) | | Home(a) | $ | 1,542 | | | $ | 702 | | | $ | 474 | | | $ | 0 | | | $ | 2,718 | |
| Business | | Business | 572 | | | 2,841 | | | 31 | | | 0 | | | 3,444 | |
| Total retail revenue | Total retail revenue | 1,521 | | | 311 | | | — | | | — | | | 1,832 | | Total retail revenue | 2,114 | | | 3,543 | | | 505 | | | 0 | | | 6,162 | |
Energy revenue(a)(c) | Energy revenue(a)(c) | 5 | | | 19 | | | 60 | | | (1) | | | 83 | | Energy revenue(a)(c) | 285 | | | 126 | | | 70 | | | 1 | | | 482 | |
Capacity revenue(a)(c) | Capacity revenue(a)(c) | — | | | 179 | | | 16 | | | — | | | 195 | | Capacity revenue(a)(c) | 0 | | | 141 | | | 14 | | | 0 | | | 155 | |
Mark-to-market for economic hedging activities(b)(d) | Mark-to-market for economic hedging activities(b)(d) | — | | | 40 | | | 1 | | | 2 | | | 43 | | Mark-to-market for economic hedging activities(b)(d) | (1) | | | (4) | | | (28) | | | 1 | | | (32) | |
| Other revenue(a)(c) | Other revenue(a)(c) | 52 | | | 17 | | | 17 | | | (1) | | | 85 | | Other revenue(a)(c) | 1,304 | | | 19 | | | 4 | | | (3) | | | 1,324 | |
| Total operating revenue | Total operating revenue | 1,578 | | | 566 | | | 94 | | | — | | | 2,238 | | Total operating revenue | 3,702 | | | 3,825 | | | 565 | | | (1) | | | 8,091 | |
| Less: Lease revenue | Less: Lease revenue | — | | | 1 | | | 4 | | | — | | | 5 | | Less: Lease revenue | 0 | | | 0 | | | 2 | | | 0 | | | 2 | |
| Less: Realized and unrealized ASC 815 revenue | Less: Realized and unrealized ASC 815 revenue | 7 | | | 85 | | | 16 | | | 1 | | | 109 | | Less: Realized and unrealized ASC 815 revenue | 93 | | | 99 | | | (34) | | | 2 | | | 160 | |
| | Total revenue from contracts with customers | Total revenue from contracts with customers | $ | 1,571 | | | $ | 480 | | | $ | 74 | | | $ | (1) | | | $ | 2,124 | | Total revenue from contracts with customers | $ | 3,609 | | | $ | 3,726 | | | $ | 597 | | | $ | (3) | | | $ | 7,929 | |
| (a) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above: | | |
| (a) Home includes Services | | (a) Home includes Services |
| (b) Other Revenue in Texas includes ancillary revenues of $1.2 billion driven by high pricing during Winter Storm Uri | | (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: | | (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) | (In millions) | Texas | | East | | West/Other | | Corporate/Eliminations | | Total | (In millions) | Texas | | East | | West/Services/Other | | Corporate/Eliminations | | Total |
| Energy revenue | Energy revenue | $ | — | | | $ | 2 | | | $ | 10 | | | $ | (1) | | | $ | 11 | | Energy revenue | $ | 0 | | | $ | 60 | | | $ | (4) | | | $ | 2 | | | $ | 58 | |
| Capacity revenue | Capacity revenue | — | | | 41 | | | — | | | — | | | 41 | | Capacity revenue | 0 | | | 37 | | | 0 | | | 0 | | | 37 | |
| Other revenue | Other revenue | 7 | | | 2 | | | 5 | | | — | | | 14 | | Other revenue | 94 | | | 6 | | | (2) | | | (1) | | | 97 | |
| (b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 | | |
| (d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 | | (d) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 |
| | | Three months ended June 30, 2019 | | | Three months ended March 31, 2020 |
| (In millions) | (In millions) | Texas | | East | | West/Other | | Corporate/Eliminations | | Total | (In millions) | Texas | | East | | West/Services/Other | | Corporate/Eliminations | | Total |
| Retail revenue: | Retail revenue: | | | | | | | | | | Retail revenue: | | | | | | | | | |
| Mass Market | $ | 1,161 | | | $ | 235 | | | $ | — | | | $ | (1) | | | $ | 1,395 | | |
| Business Solutions | 272 | | | 18 | | | — | | | — | | | 290 | | |
Home(a) | | Home(a) | $ | 1,032 | | | $ | 329 | | | $ | 18 | | | $ | (1) | | | $ | 1,378 | |
| Business | | Business | 260 | | | 23 | | | 0 | | | 0 | | | 283 | |
| Total retail revenue | Total retail revenue | 1,433 | | | 253 | | | — | | | (1) | | | 1,685 | | Total retail revenue | 1,292 | | | 352 | | | 18 | | | (1) | | | 1,661 | |
Energy revenue(a)(b) | Energy revenue(a)(b) | 136 | | | 48 | | | 52 | | | — | | | 236 | | Energy revenue(a)(b) | 5 | | | 45 | | | 75 | | | (1) | | | 124 | |
Capacity revenue(a)(b) | Capacity revenue(a)(b) | — | | | 195 | | | 6 | | | — | | | 201 | | Capacity revenue(a)(b) | 0 | | | 134 | | | 15 | | | 0 | | | 149 | |
Mark-to-market for economic hedging activities(b)(c) | Mark-to-market for economic hedging activities(b)(c) | 210 | | | 16 | | | 16 | | | (1) | | | 241 | | Mark-to-market for economic hedging activities(b)(c) | 0 | | | (20) | | | 15 | | | 1 | | | (4) | |
| Other revenue(a)(b) | Other revenue(a)(b) | 58 | | | 12 | | | 32 | | | — | | | 102 | | Other revenue(a)(b) | 61 | | | 10 | | | 20 | | | (2) | | | 89 | |
| Total operating revenue | Total operating revenue | 1,837 | | | 524 | | | 106 | | | (2) | | | 2,465 | | Total operating revenue | 1,358 | | | 521 | | | 143 | | | (3) | | | 2,019 | |
| Less: Lease revenue | Less: Lease revenue | — | | | 1 | | | 4 | | | — | | | 5 | | Less: Lease revenue | 0 | | | 0 | | | 5 | | | 0 | | | 5 | |
| Less: Realized and unrealized ASC 815 revenue | Less: Realized and unrealized ASC 815 revenue | 579 | | | 64 | | | 34 | | | — | | | 677 | | Less: Realized and unrealized ASC 815 revenue | 7 | | | 39 | | | 44 | | | (1) | | | 89 | |
| | Total revenue from contracts with customers | Total revenue from contracts with customers | $ | 1,258 | | | $ | 459 | | | $ | 68 | | | $ | (2) | | | $ | 1,783 | | Total revenue from contracts with customers | $ | 1,351 | | | $ | 482 | | | $ | 94 | | | $ | (2) | | | $ | 1,925 | |
| (a) The following table represents the realized revenues related to derivative instruments that are accounted for under ASC 815 and included in the amounts above: | | |
| (a) Home includes Services | | (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: | | (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) | (In millions) | Texas | | East | | West/Other | | Corporate/Eliminations | | Total | (In millions) | Texas | | East | | West/Services/Other | | Corporate/Eliminations | | Total |
| Energy revenue | Energy revenue | $ | 355 | | | $ | 20 | | | $ | 5 | | | $ | — | | | $ | 380 | | Energy revenue | $ | 0 | | | $ | 35 | | | $ | 19 | | | $ | (1) | | | $ | 53 | |
| Capacity revenue | Capacity revenue | — | | | 29 | | | — | | | 1 | | | 30 | | Capacity revenue | 0 | | | 24 | | | 0 | | | 0 | | | 24 | |
| Other revenue | Other revenue | 14 | | | (1) | | | 13 | | | — | | | 26 | | Other revenue | 7 | | | 0 | | | 10 | | | (1) | | | 16 | |
| (b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 | | |
| (c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 | | (c) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Six months ended June 30, 2020 | | | | | | | | |
| (In millions) | Texas | | East | | West/Other | | Corporate/Eliminations | | Total |
| Retail revenue: | | | | | | | | | |
| Mass Market | $ | 2,305 | | | $ | 638 | | | $ | — | | | $ | (1) | | | $ | 2,942 | |
| Business Solutions | 508 | | | 43 | | | — | | | — | | | 551 | |
| Total retail revenue | 2,813 | | | 681 | | | — | | | (1) | | | 3,493 | |
Energy revenue(a) | 10 | | | 64 | | | 135 | | | (2) | | | 207 | |
Capacity revenue(a) | — | | | 313 | | | 31 | | | — | | | 344 | |
Mark-to-market for economic hedging activities(b) | — | | | 20 | | | 16 | | | 3 | | | 39 | |
| | | | | | | | | |
Other revenue(a) | 113 | | | 27 | | | 37 | | | (3) | | | 174 | |
| Total operating revenue | 2,936 | | | 1,105 | | | 219 | | | (3) | | | 4,257 | |
| Less: Lease revenue | — | | | 1 | | | 9 | | | — | | | 10 | |
| Less: Realized and unrealized ASC 815 revenue | 14 | | | 124 | | | 60 | | | — | | | 198 | |
| | | | | | | | | |
| Total revenue from contracts with customers | $ | 2,922 | | | $ | 980 | | | $ | 150 | | | $ | (3) | | | $ | 4,049 | |
| (a) 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/Other | | Corporate/Eliminations | | Total |
| Energy revenue | $ | — | | | $ | 37 | | | $ | 29 | | | $ | (2) | | | $ | 64 | |
| Capacity revenue | — | | | 65 | | | — | | | — | | | 65 | |
| Other revenue | 14 | | | 2 | | | 15 | | | (1) | | | 30 | |
| (b) Revenue relates entirely to unrealized gains and losses on derivative instruments accounted for under ASC 815 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Six months ended June 30, 2019 | | | | | | | | |
| (In millions) | Texas | | East | | West/Other | | Corporate/Eliminations | | Total |
| Retail revenue: | | | | | | | | | |
| Mass Market | $ | 2,156 | | | $ | 555 | | | $ | — | | | $ | (3) | | | $ | 2,708 | |
| Business Solutions | 530 | | | 36 | | | — | | | — | | | 566 | |
| Total retail revenue | 2,686 | | | 591 | | | — | | | (3) | | | 3,274 | |
Energy revenue(a) | 241 | | | 174 | | | 110 | | | 1 | | | 526 | |
Capacity revenue(a) | — | | | 339 | | | 18 | | | — | | | 357 | |
Mark-to-market for economic hedging activities(b) | 241 | | | 1 | | | 20 | | | (1) | | | 261 | |
| | | | | | | | | |
Other revenue(a) | 135 | | | 28 | | | 51 | | | (2) | | | 212 | |
| Total operating revenue | 3,303 | | | 1,133 | | | 199 | | | (5) | | | 4,630 | |
| Less: Lease revenue | — | | | 1 | | | 9 | | | — | | | 10 | |
| Less: Realized and unrealized ASC 815 revenue | 894 | | | 118 | | | 46 | | | — | | | 1,058 | |
| | | | | | | | | |
| Total revenue from contracts with customers | $ | 2,409 | | | $ | 1,014 | | | $ | 144 | | | $ | (5) | | | $ | 3,562 | |
| (a) 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/Other | | Corporate/Eliminations | | Total |
| Energy revenue | $ | 626 | | | $ | 67 | | | $ | 7 | | | $ | — | | | $ | 700 | |
| Capacity revenue | — | | | 47 | | | — | | | 1 | | | 48 | |
| Other revenue | 27 | | | 3 | | | 19 | | | — | | | 49 | |
| (b) 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 June 30, 2020March 31, 2021 and December 31, 2019:2020:
| | (In millions) | (In millions) | June 30, 2020 | | December 31, 2019 | (In millions) | March 31, 2021 | | December 31, 2020 |
| Deferred customer acquisition costs | Deferred customer acquisition costs | $ | 133 | | | $ | 133 | | Deferred customer acquisition costs | $ | 116 | | | $ | 113 | |
| | Accounts receivable, net - Contracts with customers | Accounts receivable, net - Contracts with customers | 981 | | | 1,002 | | Accounts receivable, net - Contracts with customers | 2,920 | | | 866 | |
| | Accounts receivable, net - Derivative instruments | Accounts receivable, net - Derivative instruments | 30 | | | 18 | | Accounts receivable, net - Derivative instruments | 113 | | | 33 | |
| Accounts receivable, net - Affiliate | Accounts receivable, net - Affiliate | 4 | | | 5 | | Accounts receivable, net - Affiliate | 4 | | | 5 | |
| Total accounts receivable, net | Total accounts receivable, net | $ | 1,015 | | | $ | 1,025 | | Total accounts receivable, net | $ | 3,037 | | | $ | 904 | |
| | Unbilled revenues (included within Accounts receivable, net - Contracts with customers) | Unbilled revenues (included within Accounts receivable, net - Contracts with customers) | $ | 328 | | | $ | 402 | | Unbilled revenues (included within Accounts receivable, net - Contracts with customers) | $ | 1,234 | | | $ | 393 | |
| Deferred revenues(a) | Deferred revenues(a) | 84 | | | 82 | | Deferred revenues(a) | 258 | | | 60 | |
(a) Deferred revenues from contracts with customers for the three months ended June 30, 2020March 31, 2021 and the year ended December 31, 20192020 were approximately $33$232 million and $24$31 million, respectively
The revenue recognized from contracts with customers during both the sixthree months ended June 30,March 31, 2021 and 2020 and 2019 relating to the deferred revenue balance at the beginning of each period was $13 million. The revenue recognized during the three months ended June 30, 2020 and 2019 relating to the deferred revenue balance at the beginning of each period was $25$23 million and $19$13 million, respectively. The change in deferred revenue balances during the three and six months ended June 30,March 31, 2021 and 2020 and 2019 was primarily due to the timing difference of when consideration was received and when the performance obligation was transferred.
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 alsoNote 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.
Note 4 — Acquisitions, Discontinued Operations and Dispositions
Acquisitions
Stream Energy Acquisition
On August 1, 2019, the Company acquired Stream Energy's retail electricity and natural gas operating in 9 states and Washington, D.C. for $329 million, including working capital and other adjustments of approximately $29 million. The acquisition increased NRG's retail portfolio by approximately 600,000 RCEs or 450,000 customers. The purchase price wasis provisionally allocated as follows:
| | | | | |
| (In millions) |
Account receivableCurrent Assets | |
| Cash and cash equivalents | $ | 98152 | |
| 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 | (73)$ | 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 net current and non-current working capitalLiabilities | 5 | |
Marketing partnershipDerivative instruments | 154562 | |
Customer relationshipsDeferred income taxes | 85433 | |
Trade name | 28 | |
Other intangible assetsnon-current liabilities | 2631 | |
Goodwill (a)
| 6 | |
StreamTotal other liabilities | 1,026 | |
| Total Liabilities | $ | 4,143 | |
| |
| Direct Energy Purchase Price | $ | 3293,664 | |
(a) Goodwill arising from the acquisition is attributed to the value of the platform acquired and the synergies expected from combining the operations of StreamDirect Energy with NRG's existing businesses. Goodwill of $5 million and $1 million was assignedexpected to the Texas and East segments, respectively, and is notbe deductible for tax purposes is $337 million.
Discontinued Operations(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
Sale of South Central Portfolio
On February 4, 2019, the Company completed the sale of the South Central Portfolio to Cleco for cash consideration of $1 billion excluding working capital and other adjustments. The Company concluded thatrecorded revenue from Direct Energy of $4,161 million and income before income tax of $134 million during the divested business metthree months ended March 31, 2021.
Pro forma comparative financial information for the criteriaDirect Energy acquisition has not been included for discontinued operations as of Decemberthe three months ended March 31, 2018,2021 and 2020, as the disposition represented a strategic shift in the business in which NRG operates and the criteria for held-for-sale were met. Ascomputation of such all prior period resultsinformation is impracticable due to pre-acquisition financial statements for the operations of the South Central Portfolio, except for the Cottonwood facility as discussed below, were reclassified as discontinued operations at December 31, 2018. In connectionreporting periods not being prepared in accordance with the transaction, NRG also entered into a transition services agreement to provide certain corporate services to the divested business.GAAP.
The South Central Portfolio includes the 1,153 MW Cottonwood natural gas generating facility. Upon the closing of the sale of the South Central Portfolio, NRG entered into an agreement with Cleco to leaseback the Cottonwood facility through 2025. Due to its continuing involvement with the Cottonwood facility, NRG did not use held-for-sale or discontinued operations treatment in accounting for the Cottonwood facility.
Summarized results of the South Central Portfolio discontinued operations were as follows:
| | | | | | | | | | | | | | | | | |
| | Three months ended | | | | Six months ended | |
| (In millions) | | | June 30, 2019 | | | | June 30, 2019 |
| Operating revenues | | | $ | — | | | | | $ | 31 | |
| Operating costs and expenses | | | — | | | | | (23) | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Gain from operations of discontinued components | | | — | | | | | 8 | |
| Gain on disposal of discontinued operations, net of tax | | | 1 | | | | | 28 | |
| Gain from discontinued operations, including disposal, net of tax | | | $ | 1 | | | | | $ | 36 | |
CarlsbadDispositions
On February 6, 2018, NRG28, 2021, the Company entered into ana definitive purchase agreement with NRG Yield and GIPGeneration Bridge, an affiliate of ArcLight Capital Partners, to sell 100%approximately 4,850 MW of fossil generating assets from its membership interestsEast 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 Carlsbad Energy Holdings LLC, which owns the Carlsbad project, for $385 million of cash consideration, excluding working capital adjustments.New York City through April 2025. The primary conditiontransaction is expected to close in the Carlsbad transactionfourth 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 completion ofEast 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 Yield and the Renewables Platform.At the time ofrecognized a gain on the sale of NRG Yield and the Renewables Platform in August 2018, the Company concluded that the Carlsbad project met the criteria for discontinued operations and accordingly, all prior period results for Carlsbad were reclassified as discontinued operations. The transaction closed on February 27, 2019. Carlsbad continues to have a ground lease and easement agreement with NRG with an initial term ending in 2039 and 2, ten-year extensions. As a result$17 million, including cash disposed of the transaction, additional commitments related to the project totaled approximately $23 million as of June 30, 2020 and December 31, 2019.
Summarized results of Carlsbad discontinued operations were as follows:
| | | | | | | | | | | | | | | | | |
| | Three months ended | | | | | Six months ended |
| (In millions) | | | June 30, 2019 | | | | June 30, 2019 |
| Operating revenues | | | $ | — | | | | | $ | 19 | |
| Operating costs and expenses | | | — | | | | | (9) | |
| Other expenses | | | — | | | | | (5) | |
| | | | | | | |
| | | | | | | |
| Gain from discontinued operations, net of tax | | | — | | | | | 5 | |
| (Loss)/gain on disposal of discontinued operations, net of tax | | | (17) | | | | | 331 | |
| | | | | | | |
| Other Commitments, Indemnification and Fees | | | 27 | | | | | 27 | |
| Gain on disposal of discontinued operations, net of tax | | | 10 | | | | | 358 | |
| Gain from discontinued operations, including disposal, net of tax | | | $ | 10 | | | | | $ | 363 | |
GenOn
On June 14, 2017, the GenOn Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Texas Bankruptcy Court. As a result of the bankruptcy filings, NRG concluded that it no longer controlled GenOn as it was subject to the control of the Texas Bankruptcy Court; and accordingly, NRG deconsolidated GenOn and its subsidiaries for financial reporting purposes as of such date.
Summarized results of GenOn discontinued operations were as follows:
| | | | | | | | | | | |
| Three months ended | | Six months ended |
| (In millions) | June 30, 2019 | | June 30, 2019 |
| | | |
| | | |
| Gain from discontinued operations, net of tax | $ | 2 | | | $ | 2 | |
Dispositions$7 million.
The Company completed other asset sales for cash proceeds of $15$2 million and $18$15 million during the sixthree months ended June 30,March 31, 2021 and 2020, and 2019, 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:
| | | June 30, 2020 | | | December 31, 2019 | | | March 31, 2021 | | December 31, 2020 |
| (In millions) | (In millions) | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value | (In millions) | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| | Assets: | Assets: | | | | | | | | Assets: | | | | | | | |
Notes receivable | Notes receivable | $ | 10 | | | $ | 7 | | | $ | 11 | | | $ | 8 | | Notes receivable | $ | 2 | | | $ | 2 | | | $ | 2 | | | $ | 2 | |
| Liabilities: | Liabilities: | | Liabilities: | |
Long-term debt, including current portion (a) | Long-term debt, including current portion (a) | 5,878 | | | 6,208 | | | 5,956 | | | 6,504 | | 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
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 debt securities, non-publicly traded long-term debtthe 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 areis based on expected future cash flows discounted at market interest rates or current interest rates for similar instruments with equivalent credit qualityrate and areis 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 June 30, 2020March 31, 2021 and December 31, 2019:2020:
| | | June 30, 2020 | | | December 31, 2019 | | | March 31, 2021 | | December 31, 2020 |
| (In millions) | (In millions) | Level 2 | | Level 3 | | Level 2 | | Level 3 | (In millions) | Level 2 | | Level 3 | | Level 2 | | Level 3 |
| Long-term debt, including current portion | Long-term debt, including current portion | $ | 6,176 | | | $ | 32 | | | $ | 6,388 | | | $ | 116 | | Long-term debt, including current portion | $ | 9,182 | | | $ | 825 | | | $ | 9,446 | | | $ | 0 | |
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:
| | | June 30, 2020 | | | March 31, 2021 |
| | (In millions) | (In millions) | Total | | Level 1 | | Level 2 | | Level 3 | (In millions) | Total | | Level 1 | | Level 2 | | Level 3 |
| Investments in securities (classified within other current and non-current assets) | Investments in securities (classified within other current and non-current assets) | $ | 13 | | | $ | — | | | $ | 13 | | | $ | — | | Investments in securities (classified within other current and non-current assets) | $ | 24 | | | $ | 10 | | | $ | 14 | | | $ | 0 | |
| | Nuclear trust fund investments: | Nuclear trust fund investments: | | | Nuclear trust fund investments: | | |
| Cash and cash equivalents | Cash and cash equivalents | 26 | | | 26 | | | — | | | — | | Cash and cash equivalents | 20 | | | 20 | | | 0 | | | 0 | |
| U.S. government and federal agency obligations | U.S. government and federal agency obligations | 48 | | | 47 | | | 1 | | | — | | U.S. government and federal agency obligations | 73 | | | 72 | | | 1 | | | 0 | |
| Federal agency mortgage-backed securities | Federal agency mortgage-backed securities | 87 | | | — | | | 87 | | | — | | Federal agency mortgage-backed securities | 78 | | | 0 | | | 78 | | | 0 | |
| Commercial mortgage-backed securities | Commercial mortgage-backed securities | 38 | | | — | | | 38 | | | — | | Commercial mortgage-backed securities | 40 | | | 0 | | | 40 | | | 0 | |
| Corporate debt securities | Corporate debt securities | 148 | | | — | | | 148 | | | — | | Corporate debt securities | 136 | | | 0 | | | 136 | | | 0 | |
| Equity securities | Equity securities | 371 | | | 371 | | | — | | | — | | Equity securities | 466 | | | 466 | | | 0 | | | 0 | |
| Foreign government fixed income securities | Foreign government fixed income securities | 7 | | | — | | | 7 | | | — | | Foreign government fixed income securities | 7 | | | 1 | | | 6 | | | 0 | |
| Other trust fund investments: | Other trust fund investments: | | Other trust fund investments: | |
| U.S. government and federal agency obligations | U.S. government and federal agency obligations | 1 | | | 1 | | | — | | | — | | U.S. government and federal agency obligations | 1 | | | 1 | | | 0 | | | 0 | |
| Derivative assets: | Derivative assets: | | | Derivative assets: | | |
| Commodity contracts | Commodity contracts | 1,230 | | | 87 | | | 677 | | | 466 | | Commodity contracts | 2,824 | | | 195 | | | 2,365 | | | 264 | |
| | Measured using net asset value practical expedient: | Measured using net asset value practical expedient: | | Measured using net asset value practical expedient: | |
| Equity securities — nuclear trust fund investments | Equity securities — nuclear trust fund investments | 69 | | | Equity securities — nuclear trust fund investments | 89 | | |
| Equity securities | Equity securities | 7 | | | Equity securities | 8 | | |
| Total assets | Total assets | $ | 2,045 | | | $ | 532 | | | $ | 971 | | | $ | 466 | | Total assets | $ | 3,766 | | | $ | 765 | | | $ | 2,640 | | | $ | 264 | |
| Derivative liabilities: | Derivative liabilities: | | | | | | | | Derivative liabilities: | | | | | | | |
| Foreign exchange contracts | | Foreign exchange contracts | $ | 2 | | | $ | 0 | | | $ | 2 | | | $ | 0 | |
| Commodity contracts | Commodity contracts | $ | 1,027 | | | $ | 151 | | | $ | 562 | | | $ | 314 | | Commodity contracts | 2,438 | | | 205 | | | 2,128 | | | 105 | |
| | Total liabilities | Total liabilities | $ | 1,027 | | | $ | 151 | | | $ | 562 | | | $ | 314 | | Total liabilities | $ | 2,440 | | | $ | 205 | | | $ | 2,130 | | | $ | 105 | |
| | | December 31, 2019 | | | December 31, 2020 |
| | (In millions) | (In millions) | Total | | Level 1 | | Level 2 | | Level 3 | (In millions) | Total | | Level 1 | | Level 2 | | Level 3 |
| Investments in securities (classified within other current and non-current assets) | Investments in securities (classified within other current and non-current assets) | $ | 20 | | | $ | — | | | $ | 20 | | | $ | — | | Investments in securities (classified within other current and non-current assets) | $ | 25 | | | $ | 10 | | | $ | 15 | | | $ | 0 | |
| Nuclear trust fund investments: | Nuclear trust fund investments: | | Nuclear trust fund investments: | |
| Cash and cash equivalents | Cash and cash equivalents | 17 | | | 17 | | | — | | | — | | Cash and cash equivalents | 23 | | | 23 | | | 0 | | | 0 | |
| U.S. government and federal agency obligations | U.S. government and federal agency obligations | 68 | | | 68 | | | — | | | — | | U.S. government and federal agency obligations | 70 | | | 69 | | | 1 | | | 0 | |
| Federal agency mortgage-backed securities | Federal agency mortgage-backed securities | 100 | | | — | | | 100 | | | — | | Federal agency mortgage-backed securities | 89 | | | 0 | | | 89 | | | 0 | |
| Commercial mortgage-backed securities | Commercial mortgage-backed securities | 29 | | | — | | | 29 | | | — | | Commercial mortgage-backed securities | 36 | | | 0 | | | 36 | | | 0 | |
| Corporate debt securities | Corporate debt securities | 109 | | | — | | | 109 | | | — | | Corporate debt securities | 144 | | | 0 | | | 144 | | | 0 | |
| Equity securities | Equity securities | 388 | | | 388 | | | — | | | — | | Equity securities | 434 | | | 434 | | | 0 | | | 0 | |
| Foreign government fixed income securities | Foreign government fixed income securities | 5 | | | — | | | 5 | | | — | | Foreign government fixed income securities | 7 | | | 1 | | | 6 | | | 0 | |
| Other trust fund investments: | Other trust fund investments: | | Other trust fund investments: | |
| U.S. government and federal agency obligations | U.S. government and federal agency obligations | 1 | | | 1 | | | — | | | — | | U.S. government and federal agency obligations | 1 | | | 1 | | | 0 | | | 0 | |
| Derivative assets: | Derivative assets: | | | Derivative assets: | | |
| Commodity contracts | Commodity contracts | 1,170 | | | 84 | | | 893 | | | 193 | | Commodity contracts | 821 | | | 59 | | | 623 | | | 139 | |
| | Measured using net asset value practical expedient: | Measured using net asset value practical expedient: | | Measured using net asset value practical expedient: | |
| Equity securities — nuclear trust fund investments | Equity securities — nuclear trust fund investments | 78 | | | Equity securities — nuclear trust fund investments | 87 | | |
| Equity securities | Equity securities | 8 | | | Equity securities | 8 | | |
| Total assets | Total assets | $ | 1,993 | | | $ | 558 | | | $ | 1,156 | | | $ | 193 | | Total assets | $ | 1,745 | | | $ | 597 | | | $ | 914 | | | $ | 139 | |
| Derivative liabilities: | Derivative liabilities: | | | | | | | | Derivative liabilities: | | | | | | | |
| Commodity contracts | Commodity contracts | $ | 1,103 | | | $ | 143 | | | $ | 805 | | | $ | 155 | | Commodity contracts | $ | 884 | | | $ | 86 | | | $ | 643 | | | $ | 155 | |
| | Total liabilities | Total liabilities | $ | 1,103 | | | $ | 143 | | | $ | 805 | | | $ | 155 | | Total liabilities | $ | 884 | | | $ | 86 | | | $ | 643 | | | $ | 155 | |
The following tables reconcile,table reconciles, for the three and six months ended June 30,March 31, 2021 and 2020, and 2019, 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) | | | | Fair Value Measurement Using Significant Unobservable Inputs (Level 3) | |
| | | Three months ended
June 30, 2020 | | | | | Six months ended
June 30, 2020 | | | | Three months ended March 31, 2021 | | | Three months ended March 31, 2020 | |
| (In millions) | (In millions) | | Derivatives(a) | | | | | Derivatives(a) | | (In millions) | | Derivatives(a) | | | Derivatives(a) | |
| Beginning balance | Beginning balance | | $ | 73 | | | | | | $ | 38 | | | Beginning balance | | $ | (16) | | | | $ | 38 | | |
| | Contracts added from Direct Energy acquisition | | Contracts added from Direct Energy acquisition | | (15) | | | | 0 | | |
| | Total gains realized/unrealized— included in earnings | Total gains realized/unrealized— included in earnings | | 52 | | | | | | 74 | | | Total gains realized/unrealized— included in earnings | | 180 | | | | 22 | | |
| | Purchases | Purchases | | 8 | | | | | | 16 | | | Purchases | | 20 | | | | 8 | | |
Transfers into Level 3(b) | Transfers into Level 3(b) | | 25 | | | | | | 33 | | | Transfers into Level 3(b) | | 4 | | | | 8 | | |
Transfers out of Level 3(b) | Transfers out of Level 3(b) | | (6) | | | | | | (9) | | | Transfers out of Level 3(b) | | (14) | | | | (3) | | |
| Ending balance | Ending balance | | $ | 152 | | | | | | $ | 152 | | | Ending balance | | $ | 159 | | | | $ | 73 | | |
| Gains for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of period end | | $ | 36 | | | | | | $ | 27 | | | |
| 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 | | 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
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair Value Measurement Using Significant Unobservable Inputs (Level 3) | | | | | | | | | | | | |
| Three months ended June 30, 2019 | | | | | | | Six months ended June 30, 2019 | | | | | |
| (In millions) | Debt Securities | | | Derivatives(a) | | Total | | Debt Securities | | | Derivatives(a) | | Total |
| Beginning balance | $ | 18 | | | | $ | (2) | | | $ | 16 | | | 19 | | | | $ | 20 | | | $ | 39 | |
| Contracts added from acquisitions | — | | | | (1) | | | (1) | | | — | | | | (1) | | | (1) | |
| | | | | | | | | | | | | |
| Total gains/(losses) realized/unrealized— included in earnings | 1 | | | | (17) | | | (16) | | | 1 | | | | (27) | | | (26) | |
| | | | | | | | | | | | | |
| Cash received | — | | | | — | | | — | | | (1) | | | | — | | | (1) | |
| Purchases | — | | | | (10) | | | (10) | | | — | | | | (12) | | | (12) | |
Transfers into Level 3(b) | — | | | | 113 | | | 113 | | | — | | | | 130 | | | 130 | |
Transfers out of Level 3(b) | — | | | | 14 | | | 14 | | | — | | | | (13) | | | (13) | |
| Ending balance | 19 | | | | 97 | | | 116 | | | 19 | | | | 97 | | | 116 | |
| 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 | 1 | | | | (19) | | | (18) | | | 1 | | | | (31) | | | (30) | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
(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 June 30, 2020,March 31, 2021, contracts valued with prices provided by models and other valuation techniques make up 38%9% of derivative assets and 31%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
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 June 30, 2020March 31, 2021 and December 31, 2019:2020:
| | | | June 30, 2020 | | | March 31, 2021 |
| | Fair Value | | | Input/Range | | | Fair Value | | Input/Range |
| (In millions) | (In millions) | Assets | | Liabilities | | Valuation Technique | | Significant Unobservable Input | | Low | | High | | Weighted Average | (In millions) | Assets | | Liabilities | | Valuation Technique | | Significant Unobservable Input | | Low | | High | | Weighted Average |
| Natural Gas Contracts | | Natural Gas Contracts | $ | 3 | | | $ | 0 | | | Discounted Cash Flow | | Forward Market Price (per MMBtu) | | $ | 1 | | | $ | 16 | | | $ | 14 | |
| Power Contracts | Power Contracts | $ | 431 | | | $ | 306 | | | Discounted Cash Flow | | Forward Market Price (per MWh) | | $ | 4 | | | $ | 181 | | | $ | 26 | | Power Contracts | 234 | | | 91 | | | Discounted Cash Flow | | Forward Market Price (per MWh) | | 1 | | | 237 | | | 29 | |
| | FTRs | FTRs | 35 | | | 8 | | | Discounted Cash Flow | | Auction Prices (per MWh) | | (55) | | | 48 | | | 0 | FTRs | 27 | | | 14 | | | Discounted Cash Flow | | Auction Prices (per MWh) | | (33) | | | 320 | | | 0 |
| | $ | 466 | | | $ | 314 | | | | $ | 264 | | | $ | 105 | | |
|
| | | | December 31, 2019 | | | December 31, 2020 |
| | Fair Value | | | Input/Range | | | Fair Value | | Input/Range |
| (In millions) | (In millions) | Assets | | Liabilities | | Valuation Technique | | Significant Unobservable Input | | Low | | High | | Weighted Average | (In millions) | Assets | | Liabilities | | Valuation Technique | | Significant Unobservable Input | | Low | | High | | Weighted Average |
| Power Contracts | Power Contracts | $ | 151 | | | $ | 139 | | | Discounted Cash Flow | | Forward Market Price (per MWh) | | $ | 8 | | | $ | 218 | | | $ | 24 | | Power Contracts | $ | 111 | | | $ | 143 | | | Discounted Cash Flow | | Forward Market Price (per MWh) | | $ | 10 | | | $ | 105 | | | $ | 21 | |
| | FTRs | FTRs | 42 | | | 16 | | | Discounted Cash Flow | | Auction Prices (per MWh) | | (105) | | | 213 | | | 0 | FTRs | 28 | | | 12 | | | Discounted Cash Flow | | Auction Prices (per MWh) | | (28) | | | 43 | | | 0 |
| | $ | 193 | | | $ | 155 | | | | $ | 139 | | | $ | 155 | | |
|
The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of June 30, 2020March 31, 2021 and December 31, 2019:2020:
| | | | | | | | | | | | | | | | | | | | |
| 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 June 30,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 $1$2 million decrease in operating revenue andincrease primarily within cost of operations. As of December 31, 2019, the credit reserve did not result in a significant change in fair value in operating revenue and 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 20192020 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 20192020 Form 10-K. As of June 30, 2020,March 31, 2021, counterparty credit exposure, excluding credit exposure from RTOs, ISOs, registered commodity exchanges and certain long-term agreements, was $339$811 million and NRG held collateral (cash and letters of credit) against those positions of $76$140 million, resulting in a net exposure of $263$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.
Approximately 49%43% of the Company's exposure before collateral is expected to roll off by the end of 2021.2022. 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 | 7779 | % |
| Financial institutions | 2321 | |
| |
Total as of June 30, 2020March 31, 2021 | 100 | % |
| | | | | |
| | Net Exposure (a)(b) |
| Category by Counterparty Credit Quality | (% of Total) |
| Investment grade | 5961 | % |
| Non-investment grade/non-rated | 4139 | |
Total as of June 30, 2020March 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 $57 million ofno exposure to 2 wholesale counterparties in excess of 10% of total net exposure discussed above as of June 30, 2020.March 31, 2021. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given
During Winter Storm Uri, the credit quality, diversification and termCompany 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, incannot determine with certainty what the portfolio, NRG does not anticipateamount of its ultimate recovery will be. The full exposure was recorded as a material impact on its financial position or resultsprovision for credit losses as of operations from nonperformance by any of NRG's counterparties.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, orwhereas in the case of ERCOT, it is approved by the PUCT, and includeswhereas 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 June 30, 2020,March 31, 2021, aggregate credit risk exposure managed by NRG to these counterparties was approximately $672$925 million for the next five years.
Retail Customer Credit Risk
The Company is exposed to retail credit risk through the Company's retail electricity and gas providers, which serve C&I customersHome and the Mass market.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 June 30, 2020,March 31, 2021, the Company's retail customer credit exposure to C&IHome and MassBusiness customers was diversified across many customers and various industries, as well as government entities. TheAs a result of Winter Storm Uri, the Company is also subjectincurred additional credit losses from Business customers primarily due to risk with respecta 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 its residential solar customers. Current economic conditions may affect the Company's customers' ability to pay billsmeet their obligations in a timely manner, which could increase customer delinquencies and may lead to an increase in credit losses.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 June 30, 2020 | | | As of December 31, 2019 | | | As of March 31, 2021 | | As of December 31, 2020 |
| (In millions, except maturities) | (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) | (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 | Cash and cash equivalents | $ | 26 | | | $ | — | | | $ | — | | | — | | | $ | 17 | | | $ | — | | | $ | — | | | — | | Cash and cash equivalents | $ | 20 | | | $ | 0 | | | $ | 0 | | | — | | | $ | 23 | | | $ | 0 | | | $ | 0 | | | — | |
| U.S. government and federal agency obligations | U.S. government and federal agency obligations | 48 | | | 8 | | | — | | | 13 | | 68 | | | 4 | | | — | | | 11 | U.S. government and federal agency obligations | 73 | | | 4 | | | 2 | | | 12 | | 70 | | | 6 | | | 0 | | | 10 |
| Federal agency mortgage-backed securities | Federal agency mortgage-backed securities | 87 | | | 4 | | | — | | | 24 | | 100 | | | 3 | | | — | | | 24 | Federal agency mortgage-backed securities | 78 | | | 3 | | | 0 | | | 23 | | 89 | | | 4 | | | 0 | | | 24 |
| Commercial mortgage-backed securities | Commercial mortgage-backed securities | 38 | | | 2 | | | — | | | 27 | | 29 | | | 1 | | | 1 | | | 24 | Commercial mortgage-backed securities | 40 | | | 1 | | | 0 | | | 28 | | 36 | | | 2 | | | 0 | | | 27 |
| Corporate debt securities | Corporate debt securities | 148 | | | 12 | | | 1 | | | 12 | | 109 | | | 6 | | | — | | | 11 | Corporate debt securities | 136 | | | 7 | | | 1 | | | 12 | | 144 | | | 13 | | | 0 | | | 12 |
| Equity securities | Equity securities | 440 | | | 298 | | | — | | | — | | | 466 | | | 324 | | | — | | | — | | Equity securities | 555 | | | 403 | | | 0 | | | — | | | 521 | | | 372 | | | 0 | | | — | |
| Foreign government fixed income securities | Foreign government fixed income securities | 7 | | | 1 | | | — | | | 10 | | 5 | | | — | | | — | | | 10 | Foreign government fixed income securities | 7 | | | 0 | | | 0 | | | 9 | | 7 | | | 1 | | | 0 | | | 10 |
| Total | Total | $ | 794 | | | $ | 325 | | | $ | 1 | | | $ | 794 | | | $ | 338 | | | $ | 1 | | | Total | $ | 909 | | | $ | 418 | | | $ | 3 | | | $ | 890 | | | $ | 398 | | | $ | 0 | | |
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.
| | | | Six months ended June 30, | | | Three months ended March 31, |
| (In millions) | (In millions) | 2020 | | 2019 | (In millions) | 2021 | | 2020 |
| Realized gains | Realized gains | $ | 7 | | | $ | 5 | | Realized gains | $ | 3 | | | $ | 2 | |
| Realized losses | Realized losses | (9) | | | (5) | | Realized losses | (2) | | | (5) | |
| Proceeds from sale of securities | Proceeds from sale of securities | 220 | | | 191 | | Proceeds from sale of securities | 118 | | | 112 | |
Note 7 — Accounting for Derivative Instruments and Hedging Activities
Energy-Related Commodities
As of June 30, 2020,March 31, 2021, NRG had energy-related derivative instruments extending through 2034.2036. 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.
Interest Rate SwapsForeign Exchange Contracts
NRG wasis exposed to changes in interest rates throughforeign currency associated with the Company's issuancepurchase of variable rate debt.USD denominated natural gas for its Canadian business. In order to manage the Company's interest rateforeign exchange risk, NRG entered into interest rate swap agreements.foreign exchange contracts. As of June 30, 2020,March 31, 2021, NRG had no interest rate derivative instruments as a resultforeign exchange contracts extending through 2023. The Company marks these derivatives to market through the statement of the early termination of such contracts in connection with the repayment of the 2023 Term Loan Facility during the second quarter of 2019.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 June 30, 2020March 31, 2021 and December 31, 2019.2020. 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) | | | | Total Volume (In millions) |
| Category | Category | Units | June 30, 2020 | | December 31, 2019 | Category | Units | March 31, 2021 | | December 31, 2020 |
| Emissions | Emissions | Short Ton | 1 | | | 3 | | Emissions | Short Ton | 0 | | | 1 | |
| Renewable Energy Certificates | Renewable Energy Certificates | Certificates | 1 | | | 1 | | Renewable Energy Certificates | Certificates | 13 | | | 5 | |
| Coal | Coal | Short Ton | 5 | | | 10 | | Coal | Short Ton | 2 | | | 2 | |
| Natural Gas | Natural Gas | MMBtu | (237) | | | (181) | | Natural Gas | MMBtu | 605 | | | (286) | |
| | Power | Power | MWh | 56 | | | 38 | | Power | MWh | 201 | | | 57 | |
| Capacity | Capacity | MW/Day | (1) | | | (1) | | Capacity | MW/Day | 0 | | | (1) | |
| Foreign Exchange | | Foreign Exchange | Dollars | $ | 158 | | | $ | 0 | |
|
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 | | | Fair Value |
| | | Derivative Assets | | | Derivative Liabilities | | | Derivative Assets | | Derivative Liabilities |
| (In millions) | (In millions) | June 30, 2020 | | December 31, 2019 | | June 30, 2020 | | December 31, 2019 | (In millions) | March 31, 2021 | | December 31, 2020 | | March 31, 2021 | | December 31, 2020 |
| | Derivatives Not Designated as Cash Flow or Fair Value Hedges: | Derivatives Not Designated as Cash Flow or Fair Value Hedges: | | | | | | | | Derivatives Not Designated as Cash Flow or Fair Value Hedges: | | | | | | | |
| | Commodity contracts current | $ | 791 | | | $ | 860 | | | $ | 728 | | | $ | 781 | | |
| Commodity contracts long-term | 439 | | | 310 | | | 299 | | | 322 | | |
| Foreign exchange contracts - current | | Foreign exchange contracts - current | $ | 0 | | | $ | 0 | | | $ | 1 | | | $ | 0 | |
| Foreign exchange contracts -long-term | | Foreign exchange contracts -long-term | 0 | | | 0 | | | 1 | | | 0 | |
| Commodity contracts - current | | Commodity contracts - current | 1,816 | | | 560 | | | 1,605 | | | 499 | |
| Commodity contracts - long-term | | Commodity contracts - long-term | 1,008 | | | 261 | | | 833 | | | 385 | |
| Total Derivatives Not Designated as Cash Flow or Fair Value Hedges | Total Derivatives Not Designated as Cash Flow or Fair Value Hedges | $ | 1,230 | | | $ | 1,170 | | | $ | 1,027 | | | $ | 1,103 | | Total Derivatives Not Designated as Cash Flow or Fair Value Hedges | $ | 2,824 | | | $ | 821 | | | $ | 2,440 | | | $ | 884 | |
|
The Company has elected to present derivative assets and liabilities on the balance sheet on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. In addition, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. The following table summarizes the offsetting of derivatives by counterparty master agreement level and collateral received or paid:
| | | Gross Amounts Not Offset in the Statement of Financial Position | | | Gross Amounts Not Offset in the Statement of Financial Position |
| (In millions) | (In millions) | | Gross Amounts of Recognized Assets / Liabilities | | Derivative Instruments | | Cash Collateral (Held) / Posted | | Net Amount | (In millions) | | Gross Amounts of Recognized Assets / Liabilities | | Derivative Instruments | | Cash Collateral (Held) / Posted | | Net Amount |
| As of June 30, 2020 | | | | | | | | | |
| As of March 31, 2021 | | As of March 31, 2021 | | | | | | | | |
| Foreign exchange contracts: | | Foreign exchange contracts: | |
| | Derivative liabilities | | Derivative liabilities | | $ | (2) | | | $ | 0 | | | $ | 0 | | | $ | (2) | |
| Total foreign exchange contracts | | Total foreign exchange contracts | | $ | (2) | | | $ | 0 | | | $ | 0 | | | $ | (2) | |
| Commodity contracts: | Commodity contracts: | | Commodity contracts: | |
| Derivative assets | Derivative assets | | $ | 1,230 | | | $ | (921) | | | $ | (22) | | | $ | 287 | | Derivative assets | | $ | 2,824 | | | $ | (2,253) | | | $ | (10) | | | $ | 561 | |
| Derivative liabilities | Derivative liabilities | | (1,027) | | | 921 | | | 38 | | | (68) | | Derivative liabilities | | (2,438) | | | 2,253 | | | 0 | | | (185) | |
| Total commodity contracts | Total commodity contracts | | $ | 203 | | | $ | — | | | $ | 16 | | | $ | 219 | | Total commodity contracts | | $ | 386 | | | $ | 0 | | | $ | (10) | | | $ | 376 | |
| | Total derivative instruments | | Total derivative instruments | | $ | 384 | | | $ | 0 | | | $ | (10) | | | $ | 374 | |
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| | 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, 2019 | | | | | | | | |
| Commodity contracts: | | | | | | | | |
| Derivative assets | | $ | 1,170 | | | $ | (909) | | | $ | (7) | | | $ | 254 | |
| Derivative liabilities | | (1,103) | | | 909 | | | 73 | | | (121) | |
| Total commodity contracts | | $ | 67 | | | $ | — | | | $ | 66 | | | $ | 133 | |
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| (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 | | | 0 | | | (226) | |
| Total commodity contracts | | $ | (63) | | | $ | 0 | | | $ | (5) | | | $ | (68) | |
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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 isare included within operating revenues and cost of operations and the effect of interest rate hedges is included in interest expense.operations.
| | (In millions) | (In millions) | Three months ended June 30, | | | Six months ended June 30, | | (In millions) | Three months ended March 31, | |
| Unrealized mark-to-market results | Unrealized mark-to-market results | 2020 | | 2019 | | 2020 | | 2019 | Unrealized mark-to-market results | 2021 | | 2020 | |
| Reversal of previously recognized unrealized losses on settled positions related to economic hedges | Reversal of previously recognized unrealized losses on settled positions related to economic hedges | $ | 30 | | | $ | 11 | | | $ | 39 | | | $ | 30 | | Reversal of previously recognized unrealized losses on settled positions related to economic hedges | $ | 17 | | | $ | 9 | | |
| Reversal of acquired loss/(gain) positions related to economic hedges | 3 | | | 1 | | | 4 | | | (1) | | |
| Reversal of acquired loss positions related to economic hedges | | Reversal of acquired loss positions related to economic hedges | 145 | | | 1 | | |
| Net unrealized gains on open positions related to economic hedges | Net unrealized gains on open positions related to economic hedges | 54 | | | 9 | | | 88 | | | 12 | | Net unrealized gains on open positions related to economic hedges | 559 | | | 34 | | |
| Total unrealized mark-to-market gains for economic hedging activities | Total unrealized mark-to-market gains for economic hedging activities | 87 | | | 21 | | | 131 | | | 41 | | 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 | Reversal of previously recognized unrealized (gains) on settled positions related to trading activity | (5) | | | (1) | | | (7) | | | (7) | | 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 | Net unrealized gains on open positions related to trading activity | 4 | | | 13 | | | 17 | | | 26 | | Net unrealized gains on open positions related to trading activity | 11 | | | 13 | | |
| Total unrealized mark-to-market (losses)/gains for trading activity | (1) | | | 12 | | | 10 | | | 19 | | |
| Total unrealized mark-to-market gains for trading activity | | Total unrealized mark-to-market gains for trading activity | 4 | | | 11 | | |
| Total unrealized gains | Total unrealized gains | $ | 86 | | | $ | 33 | | | $ | 141 | | | $ | 60 | | Total unrealized gains | $ | 725 | | | $ | 55 | | |
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| Three months ended June 30, | | | | Six months ended June 30, | | |
| (In millions) | 2020 | | 2019 | | 2020 | | 2019 |
| Unrealized gains included in operating revenues | $ | 42 | | | $ | 253 | | | $ | 49 | | | $ | 280 | |
| Unrealized gains/(losses) included in cost of operations | 44 | | | (220) | | | 92 | | | (220) | |
| Total impact to statement of operations — energy commodities | $ | 86 | | | $ | 33 | | | $ | 141 | | | $ | 60 | |
| Total impact to statement of operations — interest rate contracts | $ | — | | | $ | (29) | | | $ | — | | | $ | (38) | |
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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) | | | 0 | | | | | |
| Total impact to statement of operations | $ | 725 | | | $ | 55 | | | | | |
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The reversals of acquired gain or 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 sixthree months ended June 30, 2020,March 31, 2021, the $88 million$559 unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward positions as a result ofdue to increases in outer year ERCOT power prices and decreases in New York capacity, New York power, and West/Other power prices.ERCOT heat rate expansion.
For the sixthree months ended June 30, 2019,March 31, 2020, the $12$34 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward power positions due to a decrease in West/Other power prices.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 June 30, 2020March 31, 2021 was $33$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 $8$91 million as of June 30, 2020. There will be noMarch 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 June 30, 2020.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.
Note 9 — Long-term Debt and Finance Leases
Long-term debt and finance leases consisted of the following:
| | (In millions, except rates) | (In millions, except rates) | June 30, 2020 | | December 31, 2019 | | Interest rate % | (In millions, except rates) | March 31, 2021 | | December 31, 2020 | | Interest rate % |
| Recourse debt: | Recourse debt: | | | | | | Recourse debt: | | | | | |
| Senior Notes, due 2026 | Senior Notes, due 2026 | $ | 1,000 | | | $ | 1,000 | | | 7.250 | Senior Notes, due 2026 | $ | 1,000 | | | $ | 1,000 | | | 7.250 |
| Senior Notes, due 2027 | Senior Notes, due 2027 | 1,230 | | | 1,230 | | | 6.625 | Senior Notes, due 2027 | 1,230 | | | 1,230 | | | 6.625 |
| Senior Notes, due 2028 | Senior Notes, due 2028 | 821 | | | 821 | | | 5.750 | Senior Notes, due 2028 | 821 | | | 821 | | | 5.750 |
| Senior Notes, due 2029 | Senior Notes, due 2029 | 733 | | | 733 | | | 5.250 | Senior Notes, due 2029 | 733 | | | 733 | | | 5.250 |
| Senior Notes, due 2029 | | Senior Notes, due 2029 | 500 | | | 500 | | | 3.375 |
| Senior Notes, due 2031 | | Senior Notes, due 2031 | 1,030 | | | 1,030 | | | 3.625 |
Convertible Senior Notes, due 2048(a) | Convertible Senior Notes, due 2048(a) | 575 | | | 575 | | | 2.750 | Convertible Senior Notes, due 2048(a) | 575 | | | 575 | | | 2.750 |
| Senior Secured First Lien Notes, due 2024 | Senior Secured First Lien Notes, due 2024 | 600 | | | 600 | | | 3.750 | Senior Secured First Lien Notes, due 2024 | 600 | | | 600 | | | 3.750 |
| Senior Secured First Lien Notes, due 2025 | | Senior Secured First Lien Notes, due 2025 | 500 | | | 500 | | | 2.000 |
| Senior Secured First Lien Notes, due 2027 | | Senior Secured First Lien Notes, due 2027 | 900 | | | 900 | | | 2.450 |
| Senior Secured First Lien Notes, due 2029 | Senior Secured First Lien Notes, due 2029 | 500 | | | 500 | | | 4.450 | Senior Secured First Lien Notes, due 2029 | 500 | | | 500 | | | 4.450 |
Revolving Credit Facility(b) | — | | | 83 | | | L+ 1.750 | |
| Revolving Credit Facility | | Revolving Credit Facility | 750 | | | 0 | | | L + 1.720 |
| Tax-exempt bonds | Tax-exempt bonds | 466 | | | 466 | | | 1.30 - 6.00 | Tax-exempt bonds | 466 | | | 466 | | | 1.250 - 4.750 |
| Repurchase Facility | | Repurchase Facility | 75 | | | 0 | | | L + 1.250 |
| Subtotal recourse debt | Subtotal recourse debt | 5,925 | | | 6,008 | | | Subtotal recourse debt | 9,680 | | | 8,855 | | |
| Non-recourse debt: | | | | | |
| | Other | 32 | | | 34 | | | various | |
| Subtotal all non-recourse debt | 32 | | | 34 | | | |
| Subtotal long-term debt (including current maturities) | 5,957 | | | 6,042 | | | |
| | Finance leases | | Finance leases | 16 | | | 4 | | | various |
| Subtotal long-term debt and finance leases (including current maturities) | | Subtotal long-term debt and finance leases (including current maturities) | 9,696 | | | 8,859 | | |
| Less current maturities | Less current maturities | (7) | | | (88) | | | Less current maturities | (831) | | | (1) | | |
| Less debt issuance costs | Less debt issuance costs | (61) | | | (65) | | | Less debt issuance costs | (89) | | | (93) | | |
| Discounts | Discounts | (79) | | | (86) | | | Discounts | (71) | | | (74) | | |
| Total long-term debt | Total long-term debt | $ | 5,810 | | | $ | 5,803 | | | Total long-term debt | $ | 8,705 | | | $ | 8,691 | | |
(a)As of July 31, 2020,the ex-dividend date of January 29, 2021, the Convertible Senior Notes were convertible at a price of $46.65,$45.91, which is equivalent to a conversion rate of approximately 21.4421.79 shares of common stock per $1,000 principal amount.
(b)As of December 31, 2019, the Company had drawn under its Revolving Credit Facilityex-dividend date of April 30, 2021, the Convertible Senior Notes were convertible at 1-week LIBOR + 1.750a 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
The Company had $83 million outstanding under its Revolving Credit Facility as of December 31, 2019, which was used to repayDuring the outstanding indebtedness on the Agua Caliente Borrower 1 notes on a leverage-neutral basis during the fourth quarter of 2019. Due to market conditions, primarily as a result of COVID-19, the Company drew upon the facility in the firstthird quarter of 2020, asthe 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 precautionnew 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 proportionallythe maturity date, the terms of all revolving commitments and loans made pursuant thereto are identical. The increase cashin the existing commitments, and the commitments with respect to the new tranche were effective on hand,August 20, 2020 and fully repaidbecame available upon January 5, 2021. As of March 31, 2021, total revolving commitments available, subject to usage, under the outstandingamended credit agreement was $3.7 billion. As of March 31, 2021, $750 million of borrowings duringwere 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 second quarterCompany'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 2020.
Tax-Exempt Bonds
On Marchthe P-Caps, on December 11, 2020, NRG issued $59entered 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 in aggregate principal amountto support the operations of NRG Dunkirkand its subsidiaries and
minority investments, including to replace certain letters of credit and other credit support issued for the account of entities acquired pursuant to the Direct Energy Acquisition. In addition, on December 11, 2020, 1.30% tax-exempt refinancing bonds due 2042 ("the Bonds"Trust entered into an amended and restated pledge and control agreement (the “Pledge Agreement”). The Bonds are guaranteed on, among NRG, the Trust and the Collateral Agent for the LC Issuers, under which the Trust agreed to grant a first-priority basis by eachpledge over the Eligible Treasury Assets in favor of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The Bonds are secured by a first priority security interest in the same collateral that is pledgedCollateral Agent for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion ofLC Issuers. Pursuant to the property and assets owned by NRGLC Agreement and the guarantors. The collateral securingPledge Agreement, the Bonds will, at the request of NRG, be released if NRG satisfies certain conditions, including receipt of an investment grade rating on its senior, unsecured debt securities from two out of the three rating agencies, subjectCollateral Agent is entitled to reversion if those rating agencies withdraw their investment grade rating of the Bonds or any of NRG’s senior, unsecured debt securities or downgrade such rating below investment grade. The Bonds are subject to mandatory tender and purchase on April 3, 2023 and have a final maturity date of April 1, 2042.
NRG used the net proceedsEligible Treasury Assets from the offeringTrust’s pledged account, following notice to redeemNRG, in the existing principal amountevent NRG has failed to reimburse amounts drawn under any letter of outstanding Dunkirk Power LLC 5.875% tax exempt bonds due 2042.
Non-Recourse Debt
Cottonwood - Letterscredit 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 Credit
Onany event of default under the LC Agreement (a “Collateral Enforcement Event”). The LC Agreement and the Pledge Agreement were available on January 4, 2019, the Company entered into an $805, 2021. As of March 31, 2021, $689 million credit agreement to issueof letters of credit which is currently supportingwere issued under the Cottonwood facility lease. Annual fees of 1.33% on the facility are paid quarterly in advance. As of June 30, 2020, the full $80 million was issued.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.
PG&E Bankruptcy — Agua Caliente and two of On February 3, 2021, the three Ivanpah units are party to PPAs with PG&E. Both projects have project financing with the U.S. DOE. On January 29, 2019, PG&E Corp. and primary operating subsidiary utility PG&E filed for Chapter 11 relief in the California Bankruptcy Court.As a result of the bankruptcy filing, Agua Caliente and the two Ivanpah units were issued notices of events of default under their respective loan agreements. On September 9, 2019, PG&E filed a plan of reorganization that would assume all power purchase agreements, including those held by Agua Caliente and the two Ivanpah units. The California Bankruptcy Court approved the PG&E plan and the Confirmation Order was entered on June 19, 2020. The plan went effective, and PG&E emerged from bankruptcy on July 1, 2020. On July 22, 2020 and July 24, 2020, the U.S. DOE agreed to waivers of the bankruptcy-related events of default with respect to the Agua Caliente and Ivanpah projects, respectively. The Company is working with the U.S. DOE and the partners on the Agua Caliente and Ivanpah projects to resume distributions from the projects in the near future. NRG renewed its efforts to sellsold its 35% interestownership in Agua Caliente to Clearway Energy, Inc. for $202 million as further described in July 2020, following PG&E's emergence from bankruptcy.Note 4,
NRG's maximum exposure to loss is limited to its equity investment, which was $220 million for Agua CalienteAcquisitions and $10 million for Ivanpah as of June 30, 2020.Dispositions.
Variable Interest Entities that are Consolidated
The Company has a controlling financial interest in certain entities that havehas been identified as VIEsa VIE under ASC 810. These arrangements are primarily810 in NRG Receivables LLC, which has entered into financing transactions related to tax equity arrangements entered into with third-parties in order to finance the cost of solar energy systems under operating leases eligible for certain tax creditsReceivables Facility as further described in Note 2,13, Summary of Significant Accounting Policies,Receivables Securitization and Repurchase Facility, to the Company's 2019Company’s 2020 Form 10-K. During the first quarter of 2020, the Company repurchased its partners' equity interest in one of the partnerships. As the Company retains control of its interest, the repurchase was recorded to equity.
The summarized financial information for the Company's consolidated VIEsVIE consisted of the following:
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| (In millions) | June 30, 2020 | | December 31, 2019 |
| Current assets | $ | 1 | | | $ | 3 | |
| Net property, plant and equipment | — | | | 71 | |
| Other long-term assets | 25 | | | 27 | |
| Total assets | 26 | | | 101 | |
| Current liabilities | 4 | | | 4 | |
| Long-term debt | 24 | | | 24 | |
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| Other long-term liabilities | 4 | | | 8 | |
| Total liabilities | 32 | | | 36 | |
| Redeemable noncontrolling interest | — | | | 20 | |
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| Net assets less noncontrolling interest | $ | (6) | | | $ | 45 | |
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| (In millions) | March 31, 2021 | | December 31, 2020 |
| Accounts receivable | $ | 728 | | | $ | 647 | |
| Other current assets | 1 | | | 2 | |
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| Total assets | 729 | | | 649 | |
| Current liabilities | 76 | | | 78 | |
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| Net assets | $ | 653 | | | $ | 571 | |
Note 11 — Changes in Capital Structure
As of June 30, 2020March 31, 2021 and December 31, 2019,2020, 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:
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| Issued | | Treasury | | Outstanding |
| Balance as of December 31, 2019 | 421,890,790 | | | (172,894,601) | | | 248,996,189 | |
| Shares issued under LTIPs | 1,140,987 | | | — | | | 1,140,987 | |
| Shares issued under ESPP | — | | | 63,455 | | | 63,455 | |
| Shares repurchased | — | | | (6,062,783) | | | (6,062,783) | |
| Balance as of June 30, 2020 | 423,031,777 | | | (178,893,929) | | | 244,137,848 | |
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Share Repurchases
The Company adopted, in the fourth quarter of 2019, a long-term capital allocation policy that targets allocating 50% of cash available for allocation generated each year to growth investments and 50% to be returned to shareholders. The return of capital to shareholders is expected to be completed through the increased dividend discussed below, supplemented by share repurchases. The following repurchases have been made during the six months ended June 30, 2020:
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| Total number of shares purchased | | Average price paid per share | | Amounts paid for shares purchased (in millions) | | |
| 2020 repurchases: | | | | | | | |
| Repurchases | 6,062,783 | | | | | $ | 197 | | | |
Equivalent shares purchased in lieu of tax withholdings on equity compensation issuances(a) | 710,474 | | | | | 27 | | | |
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| Total Share Repurchases during the six months ended June 30, 2020 | 6,773,257 | | | $33.05 | | $ | 224 | | | |
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| Issued | | Treasury | | Outstanding |
| Balance as of December 31, 2020 | 423,057,848 | | | (178,825,915) | | | 244,231,933 | |
| Shares issued under LTIPs | 461,273 | | | 0 | | | 461,273 | |
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| Balance as of March 31, 2021 | 423,519,121 | | | (178,825,915) | | | 244,693,206 | |
| Shares issued under LTIPs | 790 | | | 0 | | | 790 | |
| Shares issued under ESPP | 0 | | | 59,967 | | | 59,967 | |
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| Balance as of May 6, 2021 | 423,519,911 | | | (178,765,948) | | | 244,753,963 | |
(a)
NRG elected to pay cash for tax withholding on equity awards instead of issuing actual shares to management. The average price per equivalent shares withheld was $38.24
Employee Stock Purchase Plan
In March 2019, the Company reopened participation in the ESPP, which allows eligible employees to elect to withhold between 1% and 10% of their eligible compensation to purchase shares of NRG common stock at the lesser of 95% of its market value on the offering date or 95% of the fair market value on the exercise date. An offering date will occuroccurs each April 1 and October 1. An exercise date will occuroccurs each September 30 and March 31.
NRG Common Stock DividendsDirect Energy Acquisition
BeginningOn 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 firstNortheast 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 2020, NRG2021. The Company also increased its collective liquidity and collateral facilities by $3.4 billion as of the annual dividendAcquisition Closing Date to $1.20 from $0.12 per sharemeet 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 expects Finance Leases, and alsoNote 13, Receivables Securitization and Repurchase Facility, to target an annual dividend growth rate of 7-9% per share in subsequent years. A quarterly dividend of $0.30 per share was paid on the Company's common stock during2020 Form 10-K.
Acquisition costs were $22 million for the three months ended June 30, 2020. On July 17, 2020, NRG declaredMarch 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 quarterly dividendbusiness combination under ASC 805 with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the Company's common stockacquisition date. The initial accounting for the business combination is not complete because the evaluation necessary to assess the fair value of $0.30 per share, payable August 17, 2020certain net assets acquired and the amount of goodwill to stockholders of record as of August 3, 2020.
be recognized are still in process. The Company's common stock dividendsprovisional amounts are subject to available capital, market conditions,revision until the evaluations are completed to the extent that additional information is obtained about the facts and compliance with associated laws, regulations and other contractual obligations.circumstances that existed as of the acquisition date.
Note 12 — Earnings Per Share
Basic income per common share is computed by dividing net income by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted income per share is computed in a manner consistent with that of basic income per share while giving effect to all potentially dilutive common shares that were outstanding during the period. The outstanding non-qualified stock options, non-vested restricted stock units, market stock units, and relative performance stock units are not considered outstanding for purposes of computing basic income per share. However, these instruments are included in the denominator for purposes of computing diluted income per share under the treasury stock method. 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 income per share is shown in the following table:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three months ended June 30, | | | | Six months ended June 30, | | |
| (In millions, except per share data) | 2020 | | 2019 | | 2020 | | 2019 |
| Basic income per share: | | | | | | | |
| Net income available to common shareholders | $ | 313 | | | $ | 201 | | | $ | 434 | | | $ | 683 | |
| Weighted average number of common shares outstanding - basic | 245 | | | 265 | | | 246 | | | 272 | |
| Income per weighted average common share — basic | $ | 1.28 | | | $ | 0.76 | | | $ | 1.76 | | | $ | 2.51 | |
| | | | | | | |
| Diluted income per share: | | | | | | | |
| | | | | | | |
| | | | | | | |
| Net income available to common shareholders | $ | 313 | | | $ | 201 | | | $ | 434 | | | $ | 683 | |
| Weighted average number of common shares outstanding - basic | 245 | | | 265 | | | 246 | | | 272 | |
| Incremental shares attributable to the issuance of equity compensation (treasury stock method) | 1 | | | 2 | | | 1 | | | 2 | |
| Weighted average number of common shares outstanding - dilutive | 246 | | | 267 | | | 247 | | | 274 | |
| Income per weighted average common share — diluted | $ | 1.27 | | | $ | 0.75 | | | $ | 1.76 | | | $ | 2.49 | |
AsThe 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 June 30, 2020the platform acquired and 2019, the Company had an insignificant numbersynergies expected from combining the operations of outstanding equity instruments that are anti-dilutiveDirect Energy with NRG's existing businesses. Goodwill expected to be deductible for tax purposes is $337 million.
(b) The allocation of goodwill and were not includedintangible assets to the Company's reportable segments is anticipated to be completed in the computation of the Company’s diluted income per share.
Note 13 — Segment Reporting
As part of perfecting the integrated model, in which the majority of the Company’s generation serves its retail customers, the Company began managing its operations based on the combined results of the retail and wholesale generation businesses with a geographical focus in 2020. As a result, the Company changed its business segments from Retail and Generation to Texas, East and West/Other beginning in the firstsecond quarter of 2020, as further described in Note 1, Nature2021
The Company recorded revenue from Direct Energy of Business. The Company's updated segment structure reflects how management currently makes financial decisions$4,161 million and allocates resources Theincome before income tax of $134 million during the three months ended March 31, 2021.
Pro forma comparative financial information for the three and six months ended June 30, 2019 was recast to reflect the current segment structure.
In February 2019, as described in Note 4, Acquisitions, Discontinued Operations and Dispositions, the Company completed the sales of the South Central Portfolio and Carlsbad. The financial informationDirect Energy acquisition has not been included for the three and six months ended June 30, 2019 presented below reflectsMarch 31, 2021 and 2020, as the presentationcomputation of these entities as discontinued operations withinsuch information is impracticable due to pre-acquisition financial statements for the corporate segment.reporting periods not being prepared in accordance with GAAP.
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).
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three months ended June 30, 2020 | | | | | | | | | | |
| (In millions) | | Texas | | East | | West/Other | | Corporate | | Eliminations | | Total |
| Operating revenues | | $ | 1,578 | | | $ | 566 | | | $ | 94 | | | $ | — | | | $ | — | | | $ | 2,238 | |
| Depreciation and amortization | | 59 | | | 33 | | | 8 | | | 10 | | | — | | | 110 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Equity in (losses)/earnings of unconsolidated affiliates | | (3) | | | — | | | 15 | | | — | | | — | | | 12 | |
| | | | | | | | | | | | |
| Income/(loss) from continuing operations before income taxes | | 350 | | | 146 | | | 26 | | | (109) | | | 1 | | | 414 | |
| Income/(loss) from continuing operations | | 350 | | | 146 | | | 25 | | | (209) | | | 1 | | | 313 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Net income/(loss) attributable to NRG Energy, Inc | | $ | 350 | | | $ | 146 | | | $ | 25 | | | $ | (209) | | | $ | 1 | | | $ | 313 | |
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 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three months ended June 30, 2019 | | | | | | | | | | |
| (In millions) | | Texas | | East | | West/Other | | Corporate | | Eliminations | | Total |
| Operating revenues | | $ | 1,837 | | | $ | 524 | | | $ | 106 | | | $ | 1 | | | $ | (3) | | | $ | 2,465 | |
| Depreciation and amortization | | 40 | | | 30 | | | 7 | | | 8 | | | — | | | 85 | |
| Impairment losses | | 1 | | | — | | | — | | | — | | | — | | | 1 | |
| Reorganization costs | | 3 | | | — | | | — | | | (1) | | | — | | | 2 | |
| Gain on sale of assets | | — | | | — | | | — | | | 1 | | | — | | | 1 | |
| Equity in (losses)/earnings of unconsolidated affiliates | | (3) | | | — | | | 3 | | | — | | | — | | | — | |
| Loss on debt extinguishment, net | | — | | | — | | | — | | | (47) | | | — | | | (47) | |
| Income/(loss) from continuing operations before income taxes | | 259 | | | 60 | | | 18 | | | (149) | | | — | | | 188 | |
| Income/(loss) from continuing operations | | 259 | | | 60 | | | 18 | | | (148) | | | — | | | 189 | |
| Income from discontinued operations, net of tax | | — | | | — | | | — | | | 13 | | | — | | | 13 | |
| Net income/(loss) | | 259 | | | 60 | | | 18 | | | (135) | | | — | | | 202 | |
| Net income/(loss) attributable to NRG Energy, Inc. | | $ | 259 | | | $ | 60 | | | $ | 17 | | | $ | (135) | | | $ | — | | | $ | 201 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Six months ended June 30, 2020 | | | | | | | | | | |
| (In millions) | | Texas | | East | | West/Other | | Corporate | | Eliminations | | Total |
| Operating revenues | | $ | 2,936 | | | $ | 1,105 | | | $ | 219 | | | $ | — | | | $ | (3) | | | $ | 4,257 | |
| Depreciation and amortization | | 118 | | | 66 | | | 16 | | | 19 | | | — | | | 219 | |
| | | | | | | | | | | | |
| Reorganization costs | | 1 | | | — | | | — | | | 2 | | | — | | | 3 | |
| Gain on sale of assets | | — | | | — | | | 1 | | | 5 | | | — | | | 6 | |
| Equity in (losses)/earnings of unconsolidated affiliates | | (3) | | | — | | | 4 | | | — | | | — | | | 1 | |
| Impairment losses on investments | | (18) | | | — | | | — | | | — | | | — | | | (18) | |
| Loss on debt extinguishment, net | | — | | | (1) | | | — | | | — | | | — | | | (1) | |
| Income/(loss) from continuing operations before income taxes | | 512 | | | 170 | | | 67 | | | (191) | | | — | | | 558 | |
| | | | | | | | | | | | |
| Income/(loss) from continuing operations | | 512 | | | 170 | | | 66 | | | (314) | | | — | | | 434 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Net income/(loss) attributable to NRG Energy, Inc | | $ | 512 | | | $ | 170 | | | $ | 66 | | | $ | (314) | | | $ | — | | | $ | 434 | |
34
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.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Six months ended June 30, 2019 | | | | | | | | | | |
| (In millions) | | Texas | | East | | West/Other | | Corporate | | Eliminations | | Total |
| Operating revenues | | $ | 3,303 | | | $ | 1,133 | | | $ | 199 | | | $ | — | | | $ | (5) | | | $ | 4,630 | |
| Depreciation and amortization | | 80 | | | 56 | | | 18 | | | 16 | | | — | | | 170 | |
| Impairment losses | | 1 | | | — | | | — | | | — | | | — | | | 1 | |
| Reorganization costs | | 4 | | | — | | | — | | | 11 | | | — | | | 15 | |
| Gain on sale of assets | | — | | | 1 | | | — | | | 1 | | | — | | | 2 | |
| Equity in (losses) of unconsolidated affiliates | | (6) | | | — | | | (15) | | | — | | | — | | | (21) | |
| Loss on debt extinguishment, net | | — | | | — | | | — | | | (47) | | | — | | | (47) | |
| Income/(loss) from continuing operations before income taxes | | 409 | | | 159 | | | (5) | | | (276) | | | (1) | | | 286 | |
| Income/(loss) from continuing operations | | 409 | | | 159 | | | (5) | | | (279) | | | (1) | | | 283 | |
| Income from discontinued operations, net of tax | | — | | | — | | | — | | | 401 | | | — | | | 401 | |
| Net income/(loss) | | 409 | | | 159 | | | (5) | | | 122 | | | (1) | | | 684 | |
| Net income/(loss) attributable to NRG Energy, Inc. | | $ | 409 | | | $ | 159 | | | $ | (6) | | | $ | 122 | | | $ | (1) | | | $ | 683 | |
Note 145 — Income TaxesFair Value of Financial Instruments
Effective Income Tax RateFor 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 income tax provision consistedestimated 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
The fair value of the following:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three months ended June 30, | | | | Six months ended June 30, | | |
| (In millions, except rates) | 2020 | | 2019 | | 2020 | | 2019 |
| Income from continuing operations before income taxes | $ | 414 | | | $ | 188 | | | $ | 558 | | | $ | 286 | |
| Income tax expense/(benefit) from continuing operations | 101 | | | (1) | | | 124 | | | 3 | |
| | | | | | | |
| Effective income tax rate | 24.4 | % | | (0.5) | % | | 22.2 | % | | 1.0 | % |
ForCompany's publicly-traded long-term debt is based on quoted market prices and is classified as Level 2 within the three and six months ended June 30, 2020, the effective tax rates were higher than the statutory rate of 21% due to state tax expense partially offset by an excess tax benefit related to share-based compensation. For the same periods in 2019, the effective tax rates were lower than the statutory rate of 21% primarily due to the tax benefit for the change in valuation allowance partially offset by state tax expense.
On March 27, 2020, the Senate passed the CARES Act to provide emergency relief related to the COVID-19 pandemic.fair value hierarchy. The CARES Act contains federal income tax provisions which, among other things: (i) increases the amount of interest expense that businesses are allowed to deduct by increasing the adjusted taxable income limitation from 30% to 50% for tax years that begin in 2019 and 2020; (ii) permits businesses to carry back to eachestimated fair value of the five tax years NOLs arising from tax years beginning afterborrowing 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, 20172020:
| | | | | | | | | | | | | | | | | | | | | | | |
| 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 | | | $ | 0 | |
Recurring Fair Value Measurements
Debt securities, equity securities, and before January 1, 2020;trust fund investments, which are comprised of various U.S. debt and (iii) temporarily removes the 80% limitation on NOLs until tax years beginning after 2020. NRG does not expect the CARES Act provisions to have a material impactequity 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 tax positions ofCompany's condensed consolidated balance sheets on a recurring basis and their level within the Company.fair value hierarchy:
Uncertain Tax Benefits
As of June 30, 2020, NRG had a non-current tax liability of $18 million for uncertain tax benefits from positions taken on various state income tax returns and accrued interest. For the six months ended June 30, 2020, NRG accrued an immaterial amount of interest relating to the uncertain tax benefits. As of June 30, 2020, 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 2016. With few exceptions, state and local income tax examinations are no longer open for years prior to 2011. | | | | | | | | | | | | | | | | | | | | | | | |
| 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 | | | $ | 0 | |
| | | | | | | |
| Nuclear trust fund investments: | | | | | | | |
| Cash and cash equivalents | 20 | | | 20 | | | 0 | | | 0 | |
| U.S. government and federal agency obligations | 73 | | | 72 | | | 1 | | | 0 | |
| Federal agency mortgage-backed securities | 78 | | | 0 | | | 78 | | | 0 | |
| Commercial mortgage-backed securities | 40 | | | 0 | | | 40 | | | 0 | |
| Corporate debt securities | 136 | | | 0 | | | 136 | | | 0 | |
| Equity securities | 466 | | | 466 | | | 0 | | | 0 | |
| Foreign government fixed income securities | 7 | | | 1 | | | 6 | | | 0 | |
| Other trust fund investments: | | | | | | | |
| U.S. government and federal agency obligations | 1 | | | 1 | | | 0 | | | 0 | |
| 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 | | | $ | 0 | | | $ | 2 | | | $ | 0 | |
| Commodity contracts | 2,438 | | | 205 | | | 2,128 | | | 105 | |
| Total liabilities | $ | 2,440 | | | $ | 205 | | | $ | 2,130 | | | $ | 105 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| 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 | | | $ | 0 | |
| Nuclear trust fund investments: | | | | | | | |
| Cash and cash equivalents | 23 | | | 23 | | | 0 | | | 0 | |
| U.S. government and federal agency obligations | 70 | | | 69 | | | 1 | | | 0 | |
| Federal agency mortgage-backed securities | 89 | | | 0 | | | 89 | | | 0 | |
| Commercial mortgage-backed securities | 36 | | | 0 | | | 36 | | | 0 | |
| Corporate debt securities | 144 | | | 0 | | | 144 | | | 0 | |
| Equity securities | 434 | | | 434 | | | 0 | | | 0 | |
| Foreign government fixed income securities | 7 | | | 1 | | | 6 | | | 0 | |
| Other trust fund investments: | | | | | | | |
| U.S. government and federal agency obligations | 1 | | | 1 | | | 0 | | | 0 | |
| 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) | | | | | | | | 0 | | | |
| | | | | | | | | | | | | |
| 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
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 | | | $ | 0 | | | 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.
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.
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 156 — Related Party TransactionsNuclear Decommissioning Trust Fund
NRG provides services to someNRG's Nuclear Decommissioning Trust Fund assets, which are for the decommissioning of its equity method investments under operations44% interest in STP, are comprised of securities classified as available-for-sale and maintenance agreements. Feesrecorded at fair value based on actively quoted market prices. NRG accounts for the services under these agreements include recoveryNuclear 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 NRG's costsdecommissioning is the responsibility of operating the plants. Certain agreements also include fees for administrative service, a base monthly fee, profit margin and/Texas ratepayers, not NRG, all realized and unrealized gains or annual incentive bonus.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 NRG's material related party transactions with third party affiliates: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.
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three months ended June 30, | | | | Six months ended June 30, | | |
| (In millions) | 2020 | | 2019 | | 2020 | | 2019 |
| Revenues from Related Parties Included in Operating Revenues | | | | | | | |
| Gladstone | $ | — | | | $ | 1 | | | $ | 1 | | | $ | 1 | |
| | | | | | | |
Ivanpah(a) | 10 | | | 7 | | | 23 | | | 18 | |
| Midway-Sunset | 2 | | | 1 | | | 3 | | | 2 | |
| | | | | | | |
| | | | | | | |
| Total | $ | 12 | | | $ | 9 | | | $ | 27 | | | $ | 21 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 | | | $ | 0 | | | $ | 0 | | | — | | | $ | 23 | | | $ | 0 | | | $ | 0 | | | — | |
| U.S. government and federal agency obligations | 73 | | | 4 | | | 2 | | | 12 | | 70 | | | 6 | | | 0 | | | 10 |
| Federal agency mortgage-backed securities | 78 | | | 3 | | | 0 | | | 23 | | 89 | | | 4 | | | 0 | | | 24 |
| Commercial mortgage-backed securities | 40 | | | 1 | | | 0 | | | 28 | | 36 | | | 2 | | | 0 | | | 27 |
| Corporate debt securities | 136 | | | 7 | | | 1 | | | 12 | | 144 | | | 13 | | | 0 | | | 12 |
| Equity securities | 555 | | | 403 | | | 0 | | | — | | | 521 | | | 372 | | | 0 | | | — | |
| Foreign government fixed income securities | 7 | | | 0 | | | 0 | | | 9 | | 7 | | | 1 | | | 0 | | | 10 |
| Total | $ | 909 | | | $ | 418 | | | $ | 3 | | | | | $ | 890 | | | $ | 398 | | | $ | 0 | | | |
(a)
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 | |
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 | 0 | | | 1 | |
| Renewable Energy Certificates | Certificates | 13 | | | 5 | |
| Coal | Short Ton | 2 | | | 2 | |
| Natural Gas | MMBtu | 605 | | | (286) | |
| | | | |
| Power | MWh | 201 | | | 57 | |
| Capacity | MW/Day | 0 | | | (1) | |
| Foreign Exchange | Dollars | $ | 158 | | | $ | 0 | |
| | | | |
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 | $ | 0 | | | $ | 0 | | | $ | 1 | | | $ | 0 | |
| Foreign exchange contracts -long-term | 0 | | | 0 | | | 1 | | | 0 | |
| 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 | |
| | | | | | | |
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) | | | $ | 0 | | | $ | 0 | | | $ | (2) | |
| Total foreign exchange contracts | | $ | (2) | | | $ | 0 | | | $ | 0 | | | $ | (2) | |
| Commodity contracts: | | | | | | | | |
| Derivative assets | | $ | 2,824 | | | $ | (2,253) | | | $ | (10) | | | $ | 561 | |
| Derivative liabilities | | (2,438) | | | 2,253 | | | 0 | | | (185) | |
| Total commodity contracts | | $ | 386 | | | $ | 0 | | | $ | (10) | | | $ | 376 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Total derivative instruments | | $ | 384 | | | $ | 0 | | | $ | (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 | | | 0 | | | (226) | |
| Total commodity contracts | | $ | (63) | | | $ | 0 | | | $ | (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 | | | | | |
| | | | | | | | | | | | | | | |
| 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) | | | 0 | | | | | |
| 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, Also includes fees under project management agreements with each project companyFair Value of Financial Instruments, for discussion regarding concentration of credit risk.
Note 168 — Commitments and ContingenciesImpairments
Commitments2020 Impairment Losses
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 usesPetra Nova Parish Holdings — During the first lien structurequarter of 2020, due to reduce the decline in oil prices, NRG determined that the carrying amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or gas used as a proxy for power. To the extent thatCompany’s equity method investment exceeded the underlying hedge positions for a counterparty are out-of-the-money to NRG, the counterparties would have a claim under the first lien program. As of June 30, 2020, all hedges under the first lien were in-the-money for NRG on a counterparty aggregate basis.
Jewett Mine Lignite Contract
The Company's Limestone facility historically burned lignite obtained from the Jewett mine, which was operated by TWCC. On or about March 15, 2019, the Jewett mine and related lignite supply agreement with NRG were acquired by Westmoreland Jewett Mining LLC ("Jewett Mining"), a subsidiary of Westmoreland Mining LLC pursuant to a plan of reorganization confirmed by the Texas Bankruptcy Court. Effective August 5, 2020, NRG's subsidiary, NRG Texas LLC, acquired all of the equity interests of Jewett Mining. Active mining under the lignite supply agreement ceased as of December 31, 2016; however, under the terms of the lignite supply agreement, Jewett Mining remains responsible for undertaking reclamation activities and NRG is responsible for all reclamation costs. NRG has recorded an adequate ARO liability. The Railroad Commission of Texas has imposed a bond obligation of approximately $99 million for the reclamation of the Jewett mine, which NRG supports through surety bonds. The cost of the reclamation may exceed thefair value of the bonds. Additionally,investment and that the lignite supply agreement obligates NRGdecline is considered to provide additional performance assurance if required bybe other-than-temporary. In determining the Railroad Commission of Texas.
Contingencies
The Company's material legal proceedings are described below.fair value, the Company utilized an income approach to estimate future project cash flows. 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 arecorded an impairment loss is probable andof $18 million in the amountTexas segment, which included the anticipated drawdown of the loss, or range$12 million letter 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 discussedcredit posted 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 unableSeptember 2019 to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded accruals and that such difference could be material.cover certain project debt reserve requirements.
In additionNote 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 | | | 0 | | | L + 1.720 |
| Tax-exempt bonds | 466 | | | 466 | | | 1.250 - 4.750 |
| Repurchase Facility | 75 | | | 0 | | | 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 legal proceedings noted below,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 are partyand
minority investments, including to replace certain letters of credit and other litigation or legal proceedings arisingcredit 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 ordinary courseevent NRG has failed to reimburse amounts drawn under any letter 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.
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 relatedcredit issued pursuant to the installationLC Agreement, and maintenancethe LC Issuers have the right to instruct the Collateral Agent to enforce the pledge over the Eligible Treasury Assets upon the occurrence of certain pollution control technology. Plaintiffs sought damages for the alleged improper charges and a declaration as to which charges were properany event of default under the contract. In February 2020,LC Agreement (a “Collateral Enforcement Event”). The LC Agreement and the court dismissed this lawsuit without prejudice for lackPledge Agreement were available on January 5, 2021. As of subject matter jurisdiction. This matter had been appealed toMarch 31, 2021, $689 million of letters of credit were issued under the United States Court of Appeals for the Fifth Circuit, which dismissed the appeals on July 13, 2020. 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.
Sierra club et al. v. Midwest Generation LLCLC Agreement — 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 4 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.
XOOM Energy Litigation — XOOM is a defendant in 2 purported class action lawsuits pending in Maryland and New York. The plaintiffs generally claim that they did not receive the savings they were promised in their natural gas and electricity bills. The parties in the Maryland lawsuit are briefing summary judgment and class certification. In the New York case, XOOM filed a motion to dismiss, which the court granted on September 21, 2018, later entering judgment in XOOM's favor on September 24, 2018. The plaintiffs in the New York case appealed to the U.S. Court of Appeals for the Second Circuit. On July 26, 2019, the Second Circuit reversed the judgment of the district court and remanded to the district court with instructions that plaintiffs be permitted to proceed on their proposed amended complaint. This matter was known and accrued for at the time of the acquisition..
Note 1710 — Regulatory MattersInvestments Accounted for Using the Equity Method and Variable Interest Entities, or VIEs
Entities that are not Consolidated
Environmental regulatory matters are discussed within Note 18, Environmental Matters.
NRG operatesaccounts 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 a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO and RTO markets in which NRG participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRG's businesses.
In addition to the regulatory proceedings noted below, NRG and its subsidiaries are parties to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.
California Station Power — As the result of unfavorable final and non-appealable litigation,foreign currency exchange rates. On February 3, 2021, the Company accrued a liability associated with consumption of station power at the Company's Encina power plant facilitysold its 35% ownership in California after August 30, 2010. 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 established an appropriate accrual pending potential regulatory action by San Diego Gas & Electric regardinga 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 Encina facility.
South Central — On August 4, 2016, NRG received a document hold notice from FERC regarding conduct in the MISO and PJM markets. It required NRG to retain communications related to multiple generating units in the South Central region. Since sending the notice, FERC has been investigating potential violations of MISO rules involving bidding for the Big Cajun 2 facility, as well as other aspects of NRG’s operations in MISO. FERC has the authority to require disgorgement of profits and to impose penalties and NRG retains any liability following the saleconsolidated VIE consisted of the South Central Portfolio. The Company expects a preliminary finding from FERC in 2020.following:
ISO-NE — On February 5, 2019, FERC has informed the Company that it has made a preliminary finding that the Company violated FERC's market behavior rules in connection with offers made into the ISO-NE Forward Capacity Auction in 2016. On April 26, 2019, NRG responded to the preliminary findings. The Company understands that FERC is concerned that the Company was inaccurate in its communications with the Market Monitor regarding the costs and risks associated with operating certain units in the forward timeframe. NRG withdrew the bids prior to the 2016 auction in the normal course of its commercial business decision making. | | | | | | | | | | | |
| (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 1811 — Environmental MattersChanges in Capital Structure
NRG is subject to a wide rangeAs of environmental laws in the development, construction, ownershipMarch 31, 2021 and operation of projects. These laws generally require that governmental permits and approvals be obtained before construction and during operation of power plants. NRG is also subject to laws regarding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. The electric generation industry has been facing requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species that have been put in place in recent years. However, under the current U.S. presidential administration, some of these rules are being reconsidered and reviewed. In general, future laws are expected to require the addition of emissions controls or other environmental controls or to impose certain restrictions on the operations of the Company's facilities, which could have a material effect on the Company's consolidated financial position, results of operations, or cash flows. Federal and state environmental laws generally have become more stringent over time, although this trend could slow or pause in the near term with respect to federal laws under the current U.S. presidential administration.
Air
On July 8, 2019, EPA promulgated the ACE rule, which rescinded the CPP, which had sought to broadly regulate CO2 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. Numerous parties have challenged the ACE rule in the D.C. Circuit and numerous parties have filed petitions for reconsideration with the EPA.
Water
Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which would have imposed more stringent requirements (as individual permits were renewed) for wastewater streams from FGD, fly ash, bottom ash, and flue gas mercury control. On September 18, 2017, the EPA promulgated a final rule that, among other things, postpones the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA completes its next rulemaking. On April 12, 2019, the United States Court of Appeals for the Fifth Circuit addressed challenges to the rule brought by several environmental groups related to legacy wastewaters and coal ash leachate and remanded portions of the rule to the EPA. On November 22, 2019, the EPA proposed amending the 2015 ELG rule by: (x) decreasing the stringency of the selenium limit (but increasing the stringency of the nitrate and mercury limits) for FGD wastewater; (y) relaxing the zero-discharge requirement for bottom ash transport water; and (z) changing several deadlines. The Company has eliminated its estimate of the environmental capital expenditures that was anticipated. The Company will revisit these estimates after the rule is revised and as permits are renewed.
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. On August 14, 2019, the EPA proposed targeted changes to the April 2015 Rule including changes to address the August 2018 D.C. Circuit decision. On December 2, 2019, the EPA released for comment "Closure Part A Proposal" to revise the CCR Rule to address the D.C. Circuit's 2018 decision regarding the adequacy of clay-lined impoundments, obligations to close all unlined impoundments and related deadlines. On February 20,31, 2020, the EPA proposedCompany had 500,000,000 shares of common stock authorized. The following table reflects the framework for developingchanges in NRG's common stock issued and implementing a federal permit program for states that are not approved to administer the CCR rule. On March 3, 2020, the EPA proposed for comment "A Holistic Approach to Closure Part B," which proposes procedures for obtaining approval to operate existing impoundments with alternative liners. On July 29, 2020, the EPA released a prepublication (non-official) version of the final rule "A Holistic Approach to Closure Part A: Deadline to Initiate Closure," which when published in the Federal Register will amend the April 2015 Rule to address the August 2018 D.C. Circuit decision and extend some of the deadlines. The Company anticipates that the EPA will promulgate additional regulations to further amend the existing rule. The Company will update estimates of required environmental capital expenditures as the rule is revised.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 | | | 0 | | | 461,273 | |
| | | | | |
| | | | | |
| Balance as of March 31, 2021 | 423,519,121 | | | (178,825,915) | | | 244,693,206 | |
| Shares issued under LTIPs | 790 | | | 0 | | | 790 | |
| Shares issued under ESPP | 0 | | | 59,967 | | | 59,967 | |
| | | | | |
| Balance as of May 6, 2021 | 423,519,911 | | | (178,765,948) | | | 244,753,963 | |
38
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.
Note 19 — Subsequent Events
Direct Energy Acquisition
On July 24, 2020,January 5, 2021 (the "Acquisition Closing Date"), the Company entered into a definitive purchase agreement with Centrica to acquireacquired all of the issued and outstanding common shares of Direct Energy, a North American subsidiary of Centrica (the "Purchase Agreement").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 68 Canadian provinces. The acquisition will addincreased NRG's retail portfolio by over 3 million customers to NRG's business and build on and complementstrengthens its integrated model, enabling better matching of power generation with customer demand.model. It will also broadenbroadens the Company's presence in the Northeast and into states and locales where it doesdid not currentlypreviously operate, supporting NRG's objective to diversify its business.
The Company will paypaid an aggregate purchase price of $3.6$3.625 billion in cash subject to aand an initial purchase price adjustment including a working capital adjustment.of $77 million. The Company expects to fundfunded 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 $2.4$2.9 billion in newly-issued secured and unsecured corporate debt and approximately $750 millionissued in convertible preferred stock or other equity-linked instruments.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 expects to increaseincreased its collective liquidity and collateral facilities by $3.5$3.4 billion through a combinationas of new letter of credit facilities and increasethe Acquisition Closing Date to meet the additional liquidity requirements related to the existing Revolving Credit Facility.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 alsoNote 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 approval byrevision until the shareholders of Centrica, as well as customary closing conditions, consents and regulatory approvals, including the expiration or termination of the applicable waiting period under the HSR Act, and the receipt of approvals or expiration of applicable waiting periods under the Federal Power Act and the Canadian Competition Act.
The acquisition is targeted to close by December 31, 2020. Thereevaluations are no assurances that the conditionscompleted to the consummationextent that additional information is obtained about the facts and circumstances that existed as of the acquisition of Direct Energy will be satisfied, that Centrica will not seek or enter into an alternative transaction as discussed below, or that the acquisition of Direct Energy will be consummated on the terms agreed to, or at all.date.
Prior to the approval of the transaction by its shareholders, Centrica is permitted to respond to unsolicited acquisition proposals that constitute or are reasonably likely to lead to a superior proposal, and to engage in negotiations with, and provide information to, parties that submit these proposals. Centrica can terminate the Purchase Agreement to accept a superior proposal. In addition, the board of directors of Centrica can change its recommendation in favor of NRG's transaction if the failure to do so would be inconsistent with the fiduciary duties of the Centrica directors, in which case the Purchase Agreement would automatically terminate. In the event of a termination of the Purchase Agreement in connection with (i) Centrica's decision to accept a superior proposal, (ii) the failure to obtain Centrica shareholder approval, or (iii) a change of recommendation by the Centrica board, Centrica would be obligated to pay NRG a termination fee of approximately $30 million.
NRG will be required to pay Centrica a termination fee of $180 million if the Purchase Agreement is terminated (i) by either Centrica or NRG because the transaction has not been completed by July 24, 2021 (as such date may be extended for two separate three month periods if necessary to obtain required regulatory approvals, through January 24, 2022), and at the time of termination all of the mutual conditions to the obligations of NRG and Centrica to close the acquisition, and all the conditions to NRG's obligations to close the acquisition, have been satisfied other than receipt of the required antitrust and competition approvals, (ii) by either Centrica or NRG if a governmental entity has issued a judgment with respect to an antitrust or competition law that permanently prohibits the completion of the transaction and the judgment has become final and non-appealable, (iii) by NRG if a governmental entity has imposed a condition on its willingness to approve the acquisition on antitrust or competition grounds and the condition has a material adverse effect as described in the Purchase Agreement or (iv) by Centrica because NRG has breached its obligations under the Purchase Agreement to seek to obtain the antitrust and competition approvals required to complete the transaction.
Midwest Generation Lease Purchase
On July 22, 2020, Midwest Generation signed purchase agreements to acquire all of the ownership interests in the Powerton facility and Units 7 and 8 of the Joliet facility, which were being leased through 2034 and 2030, respectively, for approximately $260 million. The Company intends to fund the purchase with borrowings under its Revolving Credit Facility in an amount equal to the existing operating lease liabilities of $148 million as of June 30, 2020 and the remainder from cash-on-hand. The closing is conditioned, among other items, on the receipt of regulatory approvals from FERC and under the HSR Act.
Note 20 — Condensed Consolidating Financial InformationThe 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.
As of June 30, 2020, the Company had outstanding $4.4 billion of Senior Notes and Convertible Senior Notes due from 2026 to 2048 and outstanding $1.1 billion of Senior Secured Notes due from 2024 to 2029, as shown in Note 9,
Long-term Debt. These Senior Notes and Senior Secured Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries. These guarantees are both joint and several. The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries.
Unless otherwise noted below, eachDispositions
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 guarantor subsidiaries fullyis 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 unconditionally guaranteedequipment, net for the Senior Notes, Convertible Senior NotesEast and Senior Secured NotesWest/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
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 June 30,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 | | | $ | 0 | |
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 | | | $ | 0 | |
| | | | | | | |
| Nuclear trust fund investments: | | | | | | | |
| Cash and cash equivalents | 20 | | | 20 | | | 0 | | | 0 | |
| U.S. government and federal agency obligations | 73 | | | 72 | | | 1 | | | 0 | |
| Federal agency mortgage-backed securities | 78 | | | 0 | | | 78 | | | 0 | |
| Commercial mortgage-backed securities | 40 | | | 0 | | | 40 | | | 0 | |
| Corporate debt securities | 136 | | | 0 | | | 136 | | | 0 | |
| Equity securities | 466 | | | 466 | | | 0 | | | 0 | |
| Foreign government fixed income securities | 7 | | | 1 | | | 6 | | | 0 | |
| Other trust fund investments: | | | | | | | |
| U.S. government and federal agency obligations | 1 | | | 1 | | | 0 | | | 0 | |
| 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 | | | $ | 0 | | | $ | 2 | | | $ | 0 | |
| Commodity contracts | 2,438 | | | 205 | | | 2,128 | | | 105 | |
| Total liabilities | $ | 2,440 | | | $ | 205 | | | $ | 2,130 | | | $ | 105 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| 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 | | | $ | 0 | |
| Nuclear trust fund investments: | | | | | | | |
| Cash and cash equivalents | 23 | | | 23 | | | 0 | | | 0 | |
| U.S. government and federal agency obligations | 70 | | | 69 | | | 1 | | | 0 | |
| Federal agency mortgage-backed securities | 89 | | | 0 | | | 89 | | | 0 | |
| Commercial mortgage-backed securities | 36 | | | 0 | | | 36 | | | 0 | |
| Corporate debt securities | 144 | | | 0 | | | 144 | | | 0 | |
| Equity securities | 434 | | | 434 | | | 0 | | | 0 | |
| Foreign government fixed income securities | 7 | | | 1 | | | 6 | | | 0 | |
| Other trust fund investments: | | | | | | | |
| U.S. government and federal agency obligations | 1 | | | 1 | | | 0 | | | 0 | |
| 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) | | | | | | | | 0 | | | |
| | | | | | | | | | | | | |
| 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
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:
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| |
| March 31, 2021 |
| Fair Value | | | | Input/Range |
| (In millions) | Assets | | Liabilities | | Valuation Technique | | Significant Unobservable Input | | Low | | High | | Weighted Average |
| Natural Gas Contracts | $ | 3 | | | $ | 0 | | | 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:
| | | | | | | | |
Ace Energy, Inc. | NRG Distributed Energy Resources Holdings LLC | Reliant Energy Retail Services, LLC | | | | | | | | | |
Allied Home Warranty GP LLCSignificant Unobservable Input | | NRG Distributed Generation PR LLCPosition | RERH Holdings, LLC |
Allied Warranty LLCChange In Input | NRG Dunkirk Operations Inc. | Saguaro Power LLC |
Arthur Kill Power LLC | NRG ECOKAP Holdings LLC | SGE Energy Sourcing, LLC |
Astoria Gas Turbine Power LLC | NRG El Segundo Operations Inc. | SGE Texas Holdco, LLC |
BidURenergy, Inc. | NRG Energy Labor Services LLC | Somerset Operations Inc. |
Cabrillo Power I LLC | NRG Energy Services Group LLC | Somerset Power LLC |
Cabrillo Power II LLC | NRG Energy Services LLC | Stream Energy Columbia, LLC |
Carbon Management Solutions LLC | NRG Generation Holdings Inc. | Stream Energy Delaware, LLC |
Cirro Energy Services, Inc. | NRG Greenco LLC | Stream Energy Illinois, LLC |
Cirro Group, Inc. | NRG Home & Business Solutions LLC | Stream Energy Maryland, LLC |
Connecticut Jet Power LLC | NRG Home Services LLC | Stream Energy New Jersey, LLC |
Devon Power LLC | NRG Home Solutions LLC | Stream Energy New York, LLC |
Dunkirk Power LLC | NRG Home Solutions Product LLC | Stream Energy Pennsylvania, LLC |
Eastern Sierra Energy Company LLC | NRG Homer City Services LLC | Stream Georgia Gas SPE, LLC |
El Segundo Power II LLC | NRG HQ DG LLC | Stream Ohio Gas & Electric, LLC |
El Segundo Power, LLC | NRG Huntley Operations Inc. | Stream SPE GP, LLC |
Energy Alternatives Wholesale, LLC | NRG Identity Protect LLC | Stream SPE, Ltd. |
Energy Choice Solutions LLC | NRG Ilion Limited Partnership | Texas Genco GP, LLC |
Energy Plus Holdings LLC | NRG Ilion LP LLC | Texas Genco Holdings, Inc. |
Energy Plus Natural Gas LLC | NRG International LLC | Texas Genco LP, LLC |
Energy Protection Insurance Company | NRG Maintenance Services LLC | Texas Genco Services, LP |
Everything Energy LLC | NRG Mextrans Inc. | US Retailers LLCImpact on Fair Value Measurement |
Forward Home Security, LLCMarket Price Natural Gas/Power | | NRG Middletown Operations Inc.Buy | | Vienna Operations Inc.Increase/(Decrease) | | Higher/(Lower) |
GCP Funding Company, LLCForward Market Price Natural Gas/Power | | NRG Montville Operations Inc.Sell | | Vienna Power LLCIncrease/(Decrease) | | Lower/(Higher) |
Green Mountain Energy CompanyFTR Prices | | NRG North Central Operations Inc.Buy | | WCP (Generation) Holdings LLCIncrease/(Decrease) | | Higher/(Lower) |
Gregory Partners, LLCFTR Prices | | NRG Norwalk Harbor Operations Inc.Sell | West Coast Power LLC |
Gregory Power Partners LLCIncrease/(Decrease) | NRG Operating Services, Inc. | XOOM Alberta Holdings, LLC |
Huntley Power LLC | NRG Oswego Harbor Power Operations Inc. | XOOM British Columbia Holdings, LLC |
Independence Energy Alliance LLC | NRG Portable Power LLC | XOOM Energy California, LLC |
Independence Energy Group LLC | NRG Power Marketing LLC | XOOM Energy Connecticut, LLC |
Independence Energy Natural Gas LLC | NRG Reliability Solutions LLC | XOOM Energy Delaware, LLC |
Indian River Operations Inc. | NRG Renter's Protection LLC | XOOM Energy Georgia, LLC |
Indian River Power LLC | NRG Retail LLC | XOOM Energy Global Holdings, LLC |
Meriden Gas Turbines LLC | NRG Retail Northeast LLC | XOOM Energy Illinois LLC |
Middletown Power LLC | NRG Rockford Acquisition LLC | XOOM Energy Indiana, LLC |
Montville Power LLC | NRG Saguaro Operations Inc. | XOOM Energy Kentucky, LLC |
NEO Corporation | NRG Security LLC | XOOM Energy Maine, LLC |
New Genco GP, LLC | NRG Services Corporation | XOOM Energy Maryland, LLC |
Norwalk Power LLC | NRG SimplySmart Solutions LLC | XOOM Energy Massachusetts, LLC |
NRG Advisory Services LLC | NRG South Central Operations Inc. | XOOM Energy Michigan, LLC |
NRG Affiliate Services Inc. | NRG South Texas LP | XOOM Energy New Hampshire, LLC |
NRG Arthur Kill Operations Inc. | NRG Texas Gregory LLC | XOOM Energy New Jersey, LLC |
NRG Astoria Gas Turbine Operations Inc. | NRG Texas Holding Inc. | XOOM Energy New York, LLC |
NRG Business Services LLC | NRG Texas LLC | XOOM Energy Ohio, LLC |
NRG Cabrillo Power Operations Inc. | NRG Texas Power LLC | XOOM Energy Pennsylvania, LLC |
NRG California Peaker Operations LLC | NRG Warranty Services LLC | XOOM Energy Rhode Island, LLC |
NRG Cedar Bayou Development Company, LLC | NRG West Coast LLC | XOOM Energy Texas, LLC |
NRG Connected Home LLC | NRG Western Affiliate Services Inc. | XOOM Energy Virginia, LLC |
NRG Construction LLC | Oswego Harbor Power LLC | XOOM Energy Washington D.C., LLC |
NRG Curtailment Solutions, Inc. | Reliant Energy Northeast LLC | XOOM Energy, LLC |
NRG Development Company Inc. | Reliant Energy Power Supply, LLC | XOOM Ontario Holdings, LLC |
NRG Devon Operations Inc. | Reliant Energy Retail Holdings, LLC | XOOM Solar, LLC |
NRG Dispatch Services LLC | | 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.
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 conducts muchwith 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 business through and derives muchbilateral 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 incomeultimate 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 its subsidiaries. Therefore, the Company's abilitydefault of one member on spot market transactions be shared by the remaining participants. As a result, the counterparty credit risk to make required payments with respectthese markets is limited 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 anyNRG’s share of the guarantor subsidiaries to transfer funds to NRG. However, there may be restrictions for certain non-guarantor subsidiaries.overall market and are excluded from the above exposures.
Exchange Traded Transactions
The following condensed consolidating financial information presentsCompany enters into commodity transactions on registered exchanges, notably ICE, NYMEX and Nodal. These clearinghouses act as the financial information of NRG Energy, Inc.,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 guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 of Regulation S-XCompany values these contracts based on various techniques including, but not limited to, internal models based on a fundamental analysis of the Securities Act. The financial information may not necessarily be indicativemarket and extrapolation of resultsobservable market data with similar characteristics. Based on these valuation techniques, as of operations or financial position hadMarch 31, 2021, aggregate credit risk exposure managed by NRG to these counterparties was approximately $925 million for the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.
In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor subsidiaries and non-guarantor subsidiaries of NRG are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis.next five years.
Retail Customer Credit Risk
The Company is exposed to retail credit risk through the Company's retail electricity and gas providers, which serve Home and Business customers. Retail credit risk results in losses when a customer fails to pay for services rendered. The losses may result from both 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.
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| | 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 | | | $ | 0 | | | $ | 0 | | | — | | | $ | 23 | | | $ | 0 | | | $ | 0 | | | — | |
| U.S. government and federal agency obligations | 73 | | | 4 | | | 2 | | | 12 | | 70 | | | 6 | | | 0 | | | 10 |
| Federal agency mortgage-backed securities | 78 | | | 3 | | | 0 | | | 23 | | 89 | | | 4 | | | 0 | | | 24 |
| Commercial mortgage-backed securities | 40 | | | 1 | | | 0 | | | 28 | | 36 | | | 2 | | | 0 | | | 27 |
| Corporate debt securities | 136 | | | 7 | | | 1 | | | 12 | | 144 | | | 13 | | | 0 | | | 12 |
| Equity securities | 555 | | | 403 | | | 0 | | | — | | | 521 | | | 372 | | | 0 | | | — | |
| Foreign government fixed income securities | 7 | | | 0 | | | 0 | | | 9 | | 7 | | | 1 | | | 0 | | | 10 |
| Total | $ | 909 | | | $ | 418 | | | $ | 3 | | | | | $ | 890 | | | $ | 398 | | | $ | 0 | | | |
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 | |
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 ENERGY, INC. AND SUBSIDIARIESis 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.
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONSVolumetric 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 | 0 | | | 1 | |
| Renewable Energy Certificates | Certificates | 13 | | | 5 | |
| Coal | Short Ton | 2 | | | 2 | |
| Natural Gas | MMBtu | 605 | | | (286) | |
| | | | |
| Power | MWh | 201 | | | 57 | |
| Capacity | MW/Day | 0 | | | (1) | |
| Foreign Exchange | Dollars | $ | 158 | | | $ | 0 | |
| | | | |
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 | $ | 0 | | | $ | 0 | | | $ | 1 | | | $ | 0 | |
| Foreign exchange contracts -long-term | 0 | | | 0 | | | 1 | | | 0 | |
| 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 | |
| | | | | | | |
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) | | | $ | 0 | | | $ | 0 | | | $ | (2) | |
| Total foreign exchange contracts | | $ | (2) | | | $ | 0 | | | $ | 0 | | | $ | (2) | |
| Commodity contracts: | | | | | | | | |
| Derivative assets | | $ | 2,824 | | | $ | (2,253) | | | $ | (10) | | | $ | 561 | |
| Derivative liabilities | | (2,438) | | | 2,253 | | | 0 | | | (185) | |
| Total commodity contracts | | $ | 386 | | | $ | 0 | | | $ | (10) | | | $ | 376 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Total derivative instruments | | $ | 384 | | | $ | 0 | | | $ | (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 | | | 0 | | | (226) | |
| Total commodity contracts | | $ | (63) | | | $ | 0 | | | $ | (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 | | | | | |
| | | | | | | | | | | | | | | |
| 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) | | | 0 | | | | | |
| 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 June 30,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.
(Unaudited)Credit Risk Related Contingent Features
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc.
(Note Issuer) | | Eliminations(a) | | Consolidated |
| Operating Revenues | | | | | | | | | |
| Total operating revenues | $ | 2,055 | | | $ | 181 | | | $ | — | | | $ | 2 | | | $ | 2,238 | |
| Operating Costs and Expenses | | | | | | | | | |
| Cost of operations | 1,271 | | | 154 | | | 7 | | | 2 | | | 1,434 | |
| Depreciation and amortization | 80 | | | 20 | | | 10 | | | — | | | 110 | |
| | | | | | | | | |
| Selling, general and administrative costs | 137 | | | 7 | | | 64 | | | — | | | 208 | |
| | | | | | | | | |
| Development costs | — | | | 1 | | | 1 | | | — | | | 2 | |
| Total operating costs and expenses | 1,488 | | | 182 | | | 82 | | | 2 | | | 1,754 | |
| | | | | | | | | |
| | | | | | | | | |
| Operating Income/(Loss) | 567 | | | (1) | | | (82) | | | — | | | 484 | |
| Other Income/(Expense) | | | | | | | | | |
| Equity in earnings of consolidated subsidiaries | 3 | | | — | | | 583 | | | (586) | | | — | |
| Equity in earnings of unconsolidated affiliates | — | | | 12 | | | — | | | — | | | 12 | |
| | | | | | | | | |
| Other income, net | 7 | | | 5 | | | 2 | | | — | | | 14 | |
| | | | | | | | | |
| Interest expense | (4) | | | (2) | | | (90) | | | — | | | (96) | |
| Total other income/(expense) | 6 | | | 15 | | | 495 | | | (586) | | | (70) | |
| Income from Continuing Operations Before Income Taxes | 573 | | | 14 | | | 413 | | | (586) | | | 414 | |
| Income tax expense | — | | | 1 | | | 100 | | | — | | | 101 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Net Income | $ | 573 | | | $ | 13 | | | $ | 313 | | | $ | (586) | | | $ | 313 | |
(a)See Note 5, All significant intercompany transactions have been eliminatedFair 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 consolidationoil 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.
NRG ENERGY, INC. AND SUBSIDIARIESNote 9 — Long-term Debt and Finance Leases
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONSLong-term debt and finance leases consisted of the following:
For the six months ended June 30, 2020
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc.
(Note Issuer) | | Eliminations(a) | | Consolidated |
| Operating Revenues | | | | | | | | | |
| Total operating revenues | $ | 3,833 | | | $ | 433 | | | $ | — | | | $ | (9) | | | $ | 4,257 | |
| Operating Costs and Expenses | | | | | | | | | |
| Cost of operations | 2,561 | | | 356 | | | (17) | | | (9) | | | 2,891 | |
| Depreciation and amortization | 160 | | | 39 | | | 20 | | | — | | | 219 | |
| | | | | | | | | |
| Selling, general and administrative costs | 277 | | | 12 | | | 128 | | | — | | | 417 | |
| Reorganization costs | — | | | — | | | 3 | | | — | | | 3 | |
| Development costs | — | | | 1 | | | 4 | | | — | | | 5 | |
| Total operating costs and expenses | 2,998 | | | 408 | | | 138 | | | (9) | | | 3,535 | |
| | | | | | | | | |
| Gain on sale of assets | — | | | 1 | | | 5 | | | — | | | 6 | |
| Operating Income/(Loss) | 835 | | | 26 | | | (133) | | | — | | | 728 | |
| Other Income/(Expense) | | | | | | | | | |
| Equity in earnings of consolidated subsidiaries | 6 | | | — | | | 845 | | | (851) | | | — | |
| Equity in earnings of unconsolidated affiliates | — | | | 1 | | | — | | | — | | | 1 | |
| Impairment losses on investments | — | | | (18) | | | — | | | — | | | (18) | |
| Other income, net | 10 | | | 4 | | | 27 | | | — | | | 41 | |
| Loss on debt extinguishment, net | — | | | — | | | (1) | | | — | | | (1) | |
| Interest expense | (9) | | | (3) | | | (181) | | | — | | | (193) | |
| Total other income/(expense) | 7 | | | (16) | | | 690 | | | (851) | | | (170) | |
| Income from Continuing Operations Before Income Taxes | 842 | | | 10 | | | 557 | | | (851) | | | 558 | |
| Income tax expense | — | | | 1 | | | 123 | | | — | | | 124 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Net Income | $ | 842 | | | $ | 9 | | | $ | 434 | | | $ | (851) | | | $ | 434 | |
| | | | | | | | | | | | | | | | | |
| (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 | | | 0 | | | L + 1.720 |
| Tax-exempt bonds | 466 | | | 466 | | | 1.250 - 4.750 |
| Repurchase Facility | 75 | | | 0 | | | 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)All significant intercompany transactions have been eliminated in consolidationAs 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
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 | | | 0 | | | 461,273 | |
| | | | | |
| | | | | |
| Balance as of March 31, 2021 | 423,519,121 | | | (178,825,915) | | | 244,693,206 | |
| Shares issued under LTIPs | 790 | | | 0 | | | 790 | |
| Shares issued under ESPP | 0 | | | 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 ENERGY, INC. AND SUBSIDIARIESCommon Stock Dividends
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)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.
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) | 0 | | | 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).
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 | | | $ | 0 | | | $ | (1) | | | $ | 8,091 | |
| Depreciation and amortization | | 77 | | | 209 | | | 24 | | | 7 | | | 0 | | | 317 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Gain on sale of assets | | 0 | | | 0 | | | 17 | | | 0 | | | 0 | | | 17 | |
| Equity in losses of unconsolidated affiliates | | (1) | | | 0 | | | (5) | | | 0 | | | 0 | | | (6) | |
| | | | | | | | | | | | |
| (Loss)/income before income taxes | | (425) | | | 357 | | | 70 | | | (169) | | | 0 | | | (167) | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Net (loss)/income | | $ | (425) | | | $ | 353 | | | $ | 69 | | | $ | (79) | | | $ | 0 | | | $ | (82) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three months ended March 31, 2020 |
| (In millions) | | Texas | | East | | West/Services/Other | | Corporate | | Eliminations | | Total |
| Operating revenues | | $ | 1,358 | | | $ | 521 | | | $ | 143 | | | $ | 0 | | | $ | (3) | | | $ | 2,019 | |
| Depreciation and amortization | | 59 | | | 32 | | | 9 | | | 9 | | | 0 | | | 109 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| Gain on sale of assets | | 0 | | | 0 | | | 1 | | | 5 | | | 0 | | | 6 | |
| Equity in losses of unconsolidated affiliates | | 0 | | | 0 | | | (11) | | | 0 | | | 0 | | | (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 June 30,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,
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc.
(Note Issuer) | | Eliminations(a) | | Consolidated |
| Net Income | $ | 573 | | | $ | 13 | | | $ | 313 | | | $ | (586) | | | $ | 313 | |
| Other Comprehensive Income | | | | | | | | | |
| | | | | | | | | |
| Foreign currency translation adjustments, net | 12 | | | 13 | | | 13 | | | (25) | | | 13 | |
| | | | | | | | | |
| Defined benefit plans, net | 1 | | | — | | | — | | | (1) | | | — | |
| Other comprehensive income | 13 | | | 13 | | | 13 | | | (26) | | | 13 | |
| | | | | | | | | |
| | | | | | | | | |
| Comprehensive Income | $ | 586 | | | $ | 26 | | | $ | 326 | | | $ | (612) | | | $ | 326 | |
| | | | | | | | | |
| | | | | | | | | |
(a)All significant intercompanyUncertain 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.
The following table summarizes NRG's material related party transactions have been eliminated in consolidationwith 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.
In addition to the legal proceedings noted below, NRG ENERGY, INC. AND SUBSIDIARIESand 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.
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the six months ended June 30, 2020
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc.
(Note Issuer) | | Eliminations(a) | | Consolidated |
| Net Income | $ | 842 | | | $ | 9 | | | $ | 434 | | | $ | (851) | | | $ | 434 | |
| Other Comprehensive Loss | | | | | | | | | |
| | | | | | | | | |
| Foreign currency translation adjustments, net | (3) | | | (2) | | | (2) | | | 5 | | | (2) | |
| | | | | | | | | |
| Defined benefit plans, net | 3 | | | — | | | — | | | (3) | | | — | |
| Other comprehensive loss | — | | | (2) | | | (2) | | | 2 | | | (2) | |
| | | | | | | | | |
| | | | | | | | | |
| Comprehensive Income | $ | 842 | | | $ | 7 | | | $ | 432 | | | $ | (849) | | | $ | 432 | |
| | | | | | | | | |
| | | | | | | | | |
(a)Sierra club et al. v. Midwest Generation LLCAll significant intercompany transactions — 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 4 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 4 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 2 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 eliminatedfiled in consolidationconnection with Winter Storm Uri. At this time, the Company is unable to determine the extent or impact of these various litigation matters due to their preliminary nature. The Company intends to vigorously defend these matters.
Indemnifications and Other Contractual Arrangements
Washington-St. Tammany and Claiborne Electric Cooperative v. LaGen — On June 28, 2017, plaintiffs Washington-St. Tammany Electric Cooperative, Inc. and Claiborne Electric Cooperative, Inc. filed a lawsuit against LaGen in the United States District Court for the Middle District of Louisiana. The plaintiffs claimed breach of contract against LaGen for allegedly improperly charging the plaintiffs for costs related to the installation and maintenance of certain pollution control technology. Plaintiffs sought damages for the alleged improper charges and a declaration as to which charges were proper under the contract. In February 2020, the court dismissed this lawsuit without prejudice for lack of subject matter jurisdiction. On March 17, 2020, plaintiffs filed a lawsuit in the Nineteenth Judicial District Court for the Parish of East Baton Rouge in Louisiana alleging substantially the same matters. 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 CO2 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.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
June 30, 2020
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc.
(Note Issuer) | | Eliminations(a) | | Consolidated |
| ASSETS | | | | | | | | | |
| Current Assets | | | | | | | | | |
| Cash and cash equivalents | $ | — | | | $ | 20 | | | $ | 398 | | | $ | — | | | $ | 418 | |
| Funds deposited by counterparties | 36 | | | — | | | — | | | — | | | 36 | |
| Restricted cash | 7 | | | — | | | 1 | | | — | | | 8 | |
| Accounts receivable, net | 987 | | | 111 | | | 1,267 | | | (1,350) | | | 1,015 | |
| Inventory | 306 | | | 82 | | | — | | | — | | | 388 | |
| Derivative instruments | 789 | | | 22 | | | — | | | (20) | | | 791 | |
| Cash collateral paid in support of energy risk management activities | 133 | | | 3 | | | — | | | — | | | 136 | |
| | | | | | | | | |
| Prepayments and other current assets | 247 | | | 10 | | | 27 | | | — | | | 284 | |
| | | | | | | | | |
| | | | | | | | | |
| Total current assets | 2,505 | | | 248 | | | 1,693 | | | (1,370) | | | 3,076 | |
| Property, plant and equipment, net | 1,336 | | | 1,046 | | | 151 | | | — | | | 2,533 | |
| Other Assets | | | | | | | | | |
| Investment in subsidiaries | 170 | | | — | | | 4,525 | | | (4,695) | | | — | |
| Equity investments in affiliates | — | | | 372 | | | — | | | — | | | 372 | |
| | | | | | | | | |
| Operating lease right-of-use assets, net | 73 | | | 244 | | | 112 | | | — | | | 429 | |
| Goodwill | 400 | | | 179 | | | — | | | — | | | 579 | |
| Intangible assets, net | 695 | | | 38 | | | — | | | — | | | 733 | |
| Nuclear decommissioning trust fund | 794 | | | — | | | — | | | — | | | 794 | |
| Derivative instruments | 439 | | | 9 | | | — | | | (9) | | | 439 | |
| Deferred income taxes | 435 | | | (33) | | | 2,768 | | | — | | | 3,170 | |
| Other non-current assets | 150 | | | 27 | | | 35 | | | — | | | 212 | |
| | | | | | | | | |
| | | | | | | | | |
| Total other assets | 3,156 | | | 836 | | | 7,440 | | | (4,704) | | | 6,728 | |
| Total Assets | $ | 6,997 | | | $ | 2,130 | | | $ | 9,284 | | | $ | (6,074) | | | $ | 12,337 | |
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | | | |
| Current Liabilities | | | | | | | | | |
| Current portion of long-term debt | $ | 3 | | | $ | 4 | | | $ | — | | | $ | — | | | $ | 7 | |
| Current portion of operating lease liabilities | 19 | | | 31 | | | 19 | | | — | | | 69 | |
| Accounts payable | 809 | | | 187 | | | 1,090 | | | (1,350) | | | 736 | |
| | | | | | | | | |
| Derivative instruments | 739 | | | 9 | | | — | | | (20) | | | 728 | |
| Cash collateral received in support of energy risk management activities | 36 | | | — | | | — | | | — | | | 36 | |
| Accrued expenses and other current liabilities | 296 | | | 31 | | | 254 | | | — | | | 581 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Total current liabilities | 1,902 | | | 262 | | | 1,363 | | | (1,370) | | | 2,157 | |
| Other Liabilities | | | | | | | | | |
| Long-term debt | 245 | | | 24 | | | 5,541 | | | — | | | 5,810 | |
| Non-current operating lease liabilities | 58 | | | 290 | | | 110 | | | — | | | 458 | |
| Nuclear decommissioning reserve | 307 | | | — | | | — | | | — | | | 307 | |
| Nuclear decommissioning trust liability | 478 | | | — | | | — | | | — | | | 478 | |
| | | | | | | | | |
| Derivative instruments | 307 | | | 1 | | | — | | | (9) | | | 299 | |
| Deferred income taxes | — | | | 17 | | | — | | | — | | | 17 | |
| Other non-current liabilities | 421 | | | 120 | | | 520 | | | — | | | 1,061 | |
| | | | | | | | | |
| | | | | | | | | |
| Total other liabilities | 1,816 | | | 452 | | | 6,171 | | | (9) | | | 8,430 | |
| Total Liabilities | 3,718 | | | 714 | | | 7,534 | | | (1,379) | | | 10,587 | |
| | | | | | | | | |
| Stockholders’ Equity | 3,279 | | | 1,416 | | | 1,750 | | | (4,695) | | | 1,750 | |
| Total Liabilities and Stockholders’ Equity | $ | 6,997 | | | $ | 2,130 | | | $ | 9,284 | | | $ | (6,074) | | | $ | 12,337 | |
(a)Effluent Limitations Guidelines All significant intercompany transactions have been eliminated— 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 consolidationthe 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.
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the six months ended June 30, 2020
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc.
(Note Issuer) | | Eliminations(a) | | Consolidated |
| Cash Flows from Operating Activities | | | | | | | | | |
| Net income | $ | 842 | | | $ | 9 | | | $ | 434 | | | $ | (851) | | | $ | 434 | |
| | | | | | | | | |
| | | | | | | | | |
| Adjustments to reconcile net income/(loss) to cash provided by operating activities: | | | | | | | | | |
| Distributions from and equity in earnings/(losses) of unconsolidated affiliates and consolidated subsidiaries | (6) | | | 7 | | | (845) | | | 851 | | | 7 | |
| Depreciation and amortization | 160 | | | 39 | | | 20 | | | — | | | 219 | |
| Accretion of asset retirement obligations | 10 | | | 8 | | | — | | | — | | | 18 | |
| Provision for credit losses | 47 | | | 1 | | | — | | | — | | | 48 | |
| Amortization of nuclear fuel | 25 | | | — | | | — | | | — | | | 25 | |
| Amortization of financing costs and debt discount/premiums | — | | | — | | | 12 | | | — | | | 12 | |
| Loss on debt extinguishment, net | — | | | — | | | 1 | | | — | | | 1 | |
| Amortization of emission allowances and energy credits | 24 | | | 9 | | | — | | | — | | | 33 | |
| Amortization of unearned equity compensation | — | | | — | | | 12 | | | — | | | 12 | |
| Net gain on sale of assets and disposal of assets | (9) | | | (1) | | | (5) | | | — | | | (15) | |
| | | | | | | | | |
| Impairment losses | — | | | 18 | | | — | | | — | | | 18 | |
| Changes in derivative instruments | (144) | | | 13 | | | — | | | — | | | (131) | |
| Changes in deferred income taxes and liability for uncertain tax benefits | 1,212 | | | (154) | | | (942) | | | — | | | 116 | |
| Changes in collateral deposits in support of energy risk management activities | 53 | | | 5 | | | — | | | — | | | 58 | |
| Changes in nuclear decommissioning trust liability | 36 | | | — | | | — | | | — | | | 36 | |
| | | | | | | | | |
| | | | | | | | | |
| Changes in other working capital | (124) | | | (19) | | | (56) | | | — | | | (199) | |
| | | | | | | | | |
| | | | | | | | | |
| Net Cash Provided/(Used) by Operating Activities | 2,126 | | | (65) | | | (1,369) | | | — | | | 692 | |
| Cash Flows from Investing Activities | | | | | | | | | |
| Intercompany dividends | — | | | — | | | 1,889 | | | (1,889) | | | — | |
| Payments for acquisitions of businesses | (5) | | | — | | | — | | | — | | | (5) | |
| Capital expenditures | (78) | | | (20) | | | (18) | | | — | | | (116) | |
| | | | | | | | | |
| Net purchases of emission allowances | (4) | | | — | | | — | | | — | | | (4) | |
| Investments in nuclear decommissioning trust fund securities | (257) | | | — | | | — | | | — | | | (257) | |
| Proceeds from the sale of nuclear decommissioning trust fund securities | 220 | | | — | | | — | | | — | | | 220 | |
| Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees | 10 | | | — | | | 5 | | | — | | | 15 | |
| | | | | | | | | |
| Net contributions to investments in unconsolidated affiliates | — | | | 2 | | | — | | | — | | | 2 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Net Cash (Used)/Provided by Investing Activities | (114) | | | (18) | | | 1,876 | | | (1,889) | | | (145) | |
| Cash Flows from Financing Activities | | | | | | | | | |
| | | | | | | | | |
| Intercompany dividends and transfers | (1,941) | | | 86 | | | (34) | | | 1,889 | | | — | |
| Payments of dividends to common stockholders | — | | | — | | | (148) | | | — | | | (148) | |
| Payments for share repurchase activity | — | | | — | | | (229) | | | — | | | (229) | |
| | | | | | | | | |
| | | | | | | | | |
| Purchase of and distributions to noncontrolling interests from subsidiaries | — | | | (2) | | | — | | | — | | | (2) | |
| Proceeds from issuance of common stock | — | | | — | | | 1 | | | — | | | 1 | |
| Proceeds from issuance of long-term debt | — | | | — | | | 59 | | | — | | | 59 | |
| Payment of debt issuance costs | — | | | — | | | (1) | | | — | | | (1) | |
| Repayments of long-term debt | (60) | | | (1) | | | — | | | — | | | (61) | |
| Net repayment of Revolving Credit Facility | — | | | — | | | (83) | | | — | | | (83) | |
| | | | | | | | | |
| Other | (5) | | | — | | | — | | | — | | | (5) | |
| | | | | | | | | |
| | | | | | | | | |
| Net Cash (Used)/Provided by Financing Activities | (2,006) | | | 83 | | | (435) | | | 1,889 | | | (469) | |
| Effect of exchange rate changes on cash and cash equivalents | — | | | (1) | | | — | | | — | | | (1) | |
| | | | | | | | | |
| Net Increase/(Decrease) in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash | 6 | | | (1) | | | 72 | | | — | | | 77 | |
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period | 37 | | | 21 | | | 327 | | | — | | | 385 | |
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period | $ | 43 | | | $ | 20 | | | $ | 399 | | | $ | — | | | $ | 462 | |
(a)All significant intercompany transactions have been eliminated in consolidation
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the three months ended June 30, 2019
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc.
(Note Issuer) | | Eliminations(a) | | Consolidated |
| Operating Revenues | | | | | | | | | |
| Total operating revenues | $ | 2,140 | | | $ | 332 | | | $ | — | | | $ | (7) | | | $ | 2,465 | |
| Operating Costs and Expenses | | | | | | | | | |
| Cost of operations | 1,590 | | | 252 | | | 10 | | | (7) | | | 1,845 | |
| Depreciation and amortization | 51 | | | 26 | | | 8 | | | — | | | 85 | |
| Impairment losses | 1 | | | — | | | — | | | — | | | 1 | |
| Selling, general and administrative costs | 112 | | | 12 | | | 87 | | | — | | | 211 | |
| Reorganization costs | — | | | — | | | 2 | | | — | | | 2 | |
| Development costs | — | | | 1 | | | 1 | | | — | | | 2 | |
| Total operating costs and expenses | 1,754 | | | 291 | | | 108 | | | (7) | | | 2,146 | |
| | | | | | | | | |
| Gain on sale of assets | — | | | 1 | | | — | | | — | | | 1 | |
| Operating Income/(Loss) | 386 | | | 42 | | | (108) | | | — | | | 320 | |
| Other Income/(Expense) | | | | | | | | | |
| Equity in earnings of consolidated subsidiaries | 2 | | | — | | | 430 | | | (432) | | | — | |
| | | | | | | | | |
| | | | | | | | | |
| Other income, net | 4 | | | 8 | | | 8 | | | — | | | 20 | |
| Loss on debt extinguishment, net | — | | | — | | | (47) | | | — | | | (47) | |
| Interest expense | (3) | | | (5) | | | (97) | | | — | | | (105) | |
| Total other income/(expense) | 3 | | | 3 | | | 294 | | | (432) | | | (132) | |
| Income from Continuing Operations Before Income Taxes | 389 | | | 45 | | | 186 | | | (432) | | | 188 | |
| Income tax expense/(benefit) | — | | | 1 | | | (2) | | | — | | | (1) | |
| Income from Continuing Operations | 389 | | | 44 | | | 188 | | | (432) | | | 189 | |
| Income from discontinued operations, net of income tax | — | | | — | | | 13 | | | — | | | 13 | |
| Net Income | 389 | | | 44 | | | 201 | | | (432) | | | 202 | |
| Less: Net income attributable to noncontrolling interest and redeemable noncontrolling interest | — | | | 1 | | | — | | | — | | | 1 | |
| Net Income Attributable to NRG Energy, Inc. | $ | 389 | | | $ | 43 | | | $ | 201 | | | $ | (432) | | | $ | 201 | |
(a)All significant intercompany transactions have been eliminated in consolidation
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the six months ended June 30, 2019
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc.
(Note Issuer) | | Eliminations(a) | | Consolidated |
| Operating Revenues | | | | | | | | | |
| Total operating revenues | $ | 3,909 | | | $ | 727 | | | $ | — | | | $ | (6) | | | $ | 4,630 | |
| Operating Costs and Expenses | | | | | | | | | |
| Cost of operations | 2,948 | | | 535 | | | 19 | | | (6) | | | 3,496 | |
| Depreciation and amortization | 105 | | | 49 | | | 16 | | | — | | | 170 | |
| Impairment losses | 1 | | | — | | | — | | | — | | | 1 | |
| Selling, general and administrative costs | 234 | | | 28 | | | 143 | | | — | | | 405 | |
| Reorganization costs | — | | | — | | | 15 | | | — | | | 15 | |
| Development costs | — | | | 1 | | | 3 | | | — | | | 4 | |
| Total operating costs and expenses | 3,288 | | | 613 | | | 196 | | | (6) | | | 4,091 | |
| | | | | | | | | |
| Gain on sale of assets | 1 | | | 1 | | | — | | | — | | | 2 | |
| Operating Income/(Loss) | 622 | | | 115 | | | (196) | | | — | | | 541 | |
| Other Income/(Expense) | | | | | | | | | |
| Equity in earnings of consolidated subsidiaries | 12 | | | — | | | 729 | | | (741) | | | — | |
| Equity in losses of unconsolidated affiliates | — | | | (21) | | | — | | | — | | | (21) | |
| | | | | | | | | |
| Other income, net | 8 | | | 9 | | | 15 | | | — | | | 32 | |
| Loss on debt extinguishment, net | — | | | — | | | (47) | | | — | | | (47) | |
| Interest expense | (7) | | | (9) | | | (203) | | | — | | | (219) | |
| Total other income/(expense) | 13 | | | (21) | | | 494 | | | (741) | | | (255) | |
| Income from Continuing Operations Before Income Taxes | 635 | | | 94 | | | 298 | | | (741) | | | 286 | |
| Income tax expense | — | | | 1 | | | 2 | | | — | | | 3 | |
| Income from Continuing Operations | 635 | | | 93 | | | 296 | | | (741) | | | 283 | |
| Income from discontinued operations, net of income tax | 9 | | | 5 | | | 387 | | | — | | | 401 | |
| Net Income | 644 | | | 98 | | | 683 | | | (741) | | | 684 | |
| Less: Net income attributable to noncontrolling interest and redeemable noncontrolling interest | — | | | 1 | | | — | | | — | | | 1 | |
| Net Income Attributable to NRG Energy, Inc. | $ | 644 | | | $ | 97 | | | $ | 683 | | | $ | (741) | | | $ | 683 | |
(a)All significant intercompany transactions have been eliminated in consolidation
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the three months ended June 30, 2019
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc.
(Note Issuer) | | Eliminations(a) | | Consolidated |
| Net Income | $ | 389 | | | $ | 44 | | | $ | 201 | | | $ | (432) | | | $ | 202 | |
| Other Comprehensive Loss | | | | | | | | | |
| | | | | | | | | |
| Foreign currency translation adjustments, net | (1) | | | (1) | | | (1) | | | 2 | | | (1) | |
| Available-for-sale securities, net | — | | | — | | | 1 | | | — | | | 1 | |
| Defined benefit plans, net | — | | | — | | | (3) | | | — | | | (3) | |
| Other comprehensive loss | (1) | | | (1) | | | (3) | | | 2 | | | (3) | |
| Comprehensive Income | 388 | | | 43 | | | 198 | | | (430) | | | 199 | |
| Less: Comprehensive income attributable to redeemable noncontrolling interest | — | | | 1 | | | — | | | — | | | 1 | |
| Comprehensive Income Attributable to NRG Energy, Inc. | $ | 388 | | | $ | 42 | | | $ | 198 | | | $ | (430) | | | $ | 198 | |
| | | | | | | | | |
| | | | | | | | | |
(a)All significant intercompany transactions have been eliminated in consolidation
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME
For the six months ended June 30, 2019
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc.
(Note Issuer) | | Eliminations(a) | | Consolidated |
| Net Income | $ | 644 | | | $ | 98 | | | $ | 683 | | | $ | (741) | | | $ | 684 | |
| Other Comprehensive Loss | | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Available-for-sale securities, net | — | | | — | | | 1 | | | — | | | 1 | |
| Defined benefit plans, net | — | | | — | | | (6) | | | — | | | (6) | |
| Other comprehensive loss | — | | | — | | | (5) | | | — | | | (5) | |
| Comprehensive Income | 644 | | | 98 | | | 678 | | | (741) | | | 679 | |
| Less: Comprehensive income attributable to redeemable noncontrolling interest | — | | | 1 | | | — | | | — | | | 1 | |
| Comprehensive Income Attributable to NRG Energy, Inc. | $ | 644 | | | $ | 97 | | | $ | 678 | | | $ | (741) | | | $ | 678 | |
| | | | | | | | | |
| | | | | | | | | |
(a)All significant intercompany transactions have been eliminated in consolidation
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2019
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc.
(Note Issuer) | | Eliminations(a) | | Consolidated |
| ASSETS | | | | | | | | | |
| Current Assets | | | | | | | | | |
| Cash and cash equivalents | $ | — | | | $ | 20 | | | $ | 325 | | | $ | — | | | $ | 345 | |
| Funds deposited by counterparties | 32 | | | — | | | — | | | — | | | 32 | |
| Restricted cash | 5 | | | 1 | | | 2 | | | — | | | 8 | |
| Accounts receivable, net | 1,293 | | | 239 | | | 233 | | | (740) | | | 1,025 | |
| Inventory | 272 | | | 111 | | | — | | | — | | | 383 | |
| Derivative instruments | 856 | | | 45 | | | — | | | (41) | | | 860 | |
| Cash collateral paid in support of energy risk management activities | 182 | | | 8 | | | — | | | — | | | 190 | |
| | | | | | | | | |
| Prepayments and other current assets | 170 | | | 8 | | | 67 | | | — | | | 245 | |
| | | | | | | | | |
| | | | | | | | | |
| Total current assets | 2,810 | | | 432 | | | 627 | | | (781) | | | 3,088 | |
| Property, plant and equipment, net | 1,483 | | | 952 | | | 158 | | | — | | | 2,593 | |
| Other Assets | | | | | | | | | |
| Investment in subsidiaries | 710 | | | — | | | 4,785 | | | (5,495) | | | — | |
| Equity investments in affiliates | — | | | 388 | | | — | | | — | | | 388 | |
| | | | | | | | | |
| Operating lease right-of-use assets, net | 81 | | | 261 | | | 122 | | | — | | | 464 | |
| Goodwill | 359 | | | 220 | | | — | | | — | | | 579 | |
| Intangible assets, net | 375 | | | 414 | | | — | | | — | | | 789 | |
| Nuclear decommissioning trust fund | 794 | | | — | | | — | | | — | | | 794 | |
| Derivative instruments | 308 | | | 15 | | | — | | | (13) | | | 310 | |
| Deferred income taxes | 421 | | | (19) | | | 2,884 | | | — | | | 3,286 | |
| Other non-current assets | 145 | | | 30 | | | 65 | | | — | | | 240 | |
| | | | | | | | | |
| | | | | | | | | |
| Total other assets | 3,193 | | | 1,309 | | | 7,856 | | | (5,508) | | | 6,850 | |
| Total Assets | $ | 7,486 | | | $ | 2,693 | | | $ | 8,641 | | | $ | (6,289) | | | $ | 12,531 | |
| LIABILITIES AND STOCKHOLDERS’ EQUITY | | | | | | | | | |
| Current Liabilities | | | | | | | | | |
| Current portion of long-term debt | $ | — | | | $ | 5 | | | $ | 83 | | | $ | — | | | $ | 88 | |
| Current portion of operating lease liabilities | 20 | | | 32 | | | 21 | | | — | | | 73 | |
| Accounts payable | 918 | | | 141 | | | 403 | | | (740) | | | 722 | |
| | | | | | | | | |
| Derivative instruments | 797 | | | 25 | | | — | | | (41) | | | 781 | |
| Cash collateral received in support of energy risk management activities | 32 | | | — | | | — | | | — | | | 32 | |
| Accrued expenses and other current liabilities | 280 | | | 44 | | | 339 | | | — | | | 663 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Total current liabilities | 2,047 | | | 247 | | | 846 | | | (781) | | | 2,359 | |
| Other Liabilities | | | | | | | | | |
| Long-term debt | 302 | | | 28 | | | 5,473 | | | — | | | 5,803 | |
| Non-current operating lease liabilities | 64 | | | 301 | | | 118 | | | — | | | 483 | |
| Nuclear decommissioning reserve | 298 | | | — | | | — | | | — | | | 298 | |
| Nuclear decommissioning trust liability | 487 | | | — | | | — | | | — | | | 487 | |
| | | | | | | | | |
| Derivative instruments | 334 | | | 1 | | | — | | | (13) | | | 322 | |
| Deferred income taxes | — | | | 17 | | | — | | | — | | | 17 | |
| Other non-current liabilities | 399 | | | 153 | | | 532 | | | — | | | 1,084 | |
| | | | | | | | | |
| | | | | | | | | |
| Total other liabilities | 1,884 | | | 500 | | | 6,123 | | | (13) | | | 8,494 | |
| Total Liabilities | 3,931 | | | 747 | | | 6,969 | | | (794) | | | 10,853 | |
| Redeemable noncontrolling interest in subsidiaries | — | | | 20 | | | — | | | — | | | 20 | |
| Stockholders’ Equity | 3,555 | | | 1,926 | | | 1,672 | | | (5,495) | | | 1,658 | |
| Total Liabilities and Stockholders’ Equity | $ | 7,486 | | | $ | 2,693 | | | $ | 8,641 | | | $ | (6,289) | | | $ | 12,531 | |
(a)All significant intercompany transactions have been eliminated in consolidation
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the six months ended June 30, 2019
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Guarantor Subsidiaries | | Non-Guarantor Subsidiaries | | NRG Energy, Inc.
(Note Issuer) | | Eliminations(a) | | Consolidated |
| Cash Flows from Operating Activities | | | | | | | | | |
| Net income | $ | 644 | | | $ | 98 | | | $ | 683 | | | $ | (741) | | | $ | 684 | |
| Income from discontinued operations | 9 | | | 5 | | | 387 | | | — | | | 401 | |
| Income from continuing operations | 635 | | | 93 | | | 296 | | | (741) | | | 283 | |
| Adjustments to reconcile net income to cash provided by operating activities: | | | | | | | | | |
| Distributions from and equity in earnings/(losses) of unconsolidated affiliates and consolidated subsidiaries | (12) | | | 22 | | | (729) | | | 741 | | | 22 | |
| Depreciation and amortization | 104 | | | 50 | | | 16 | | | — | | | 170 | |
| Accretion of asset retirement obligations | 11 | | | 3 | | | — | | | — | | | 14 | |
| Provision for credit losses | 42 | | | 4 | | | 6 | | | — | | | 52 | |
| Amortization of nuclear fuel | 27 | | | — | | | — | | | — | | | 27 | |
| Amortization of financing costs and debt discount/premiums | — | | | — | | | 13 | | | — | | | 13 | |
| Loss on debt extinguishment, net | — | | | — | | | 47 | | | — | | | 47 | |
| Amortization of emission allowances and energy credits | 13 | | | 1 | | | — | | | — | | | 14 | |
| Amortization of unearned equity compensation | — | | | — | | | 10 | | | — | | | 10 | |
| Net loss on sale of assets and disposal of assets | (3) | | | 1 | | | 3 | | | — | | | 1 | |
| | | | | | | | | |
| Impairment losses | 1 | | | — | | | — | | | — | | | 1 | |
| Changes in derivative instruments | (28) | | | (32) | | | 38 | | | — | | | (22) | |
| Changes in deferred income taxes and liability for uncertain tax benefits | — | | | (3) | | | (2) | | | — | | | (5) | |
| Changes in collateral deposits in support of energy risk management activities | 128 | | | (3) | | | — | | | — | | | 125 | |
| Changes in nuclear decommissioning trust liability | 17 | | | — | | | — | | | — | | | 17 | |
| | | | | | | | | |
| | | | | | | | | |
| Changes in other working capital | (343) | | | (64) | | | 55 | | | — | | | (352) | |
| Cash provided/(used) by continuing operations | 592 | | | 72 | | | (247) | | | — | | | 417 | |
| Cash provided/(used) by discontinued operations | 17 | | | (9) | | | — | | | — | | | 8 | |
| Net Cash Provided/(Used) by Operating Activities | 609 | | | 63 | | | (247) | | | — | | | 425 | |
| Cash Flows from Investing Activities | | | | | | | | | |
| Intercompany dividends | — | | | — | | | 2,209 | | | (2,209) | | | — | |
| Payments for acquisitions of businesses | (21) | | | — | | | — | | | — | | | (21) | |
| Capital expenditures | (77) | | | (15) | | | (15) | | | — | | | (107) | |
| | | | | | | | | |
| Net purchases of emission allowances | (1) | | | — | | | — | | | — | | | (1) | |
| Investments in nuclear decommissioning trust fund securities | (209) | | | — | | | — | | | — | | | (209) | |
| Proceeds from the sale of nuclear decommissioning trust fund securities | 191 | | | — | | | — | | | — | | | 191 | |
| Proceeds from sale of assets, net of cash disposed and sale of discontinued operations, net of fees | 1 | | | 400 | | | 888 | | | — | | | 1,289 | |
| | | | | | | | | |
| Net distributions from investments in unconsolidated affiliates | — | | | 7 | | | — | | | — | | | 7 | |
| Contributions to discontinued operations | — | | | (44) | | | — | | | — | | | (44) | |
| | | | | | | | | |
| Cash (used)/provided by continuing operations | (116) | | | 348 | | | 3,082 | | | (2,209) | | | 1,105 | |
| Cash used by discontinued operations | — | | | (2) | | | — | | | — | | | (2) | |
| Net Cash (Used)/Provided by Investing Activities | (116) | | | 346 | | | 3,082 | | | (2,209) | | | 1,103 | |
| Cash Flows from Financing Activities | | | | | | | | | |
| | | | | | | | | |
| Intercompany dividends and transfers | (532) | | | (375) | | | (1,302) | | | 2,209 | | | — | |
| Payment of dividends to common stockholders | — | | | — | | | (16) | | | — | | | (16) | |
| Payments for share repurchase activity | — | | | — | | | (1,075) | | | — | | | (1,075) | |
| | | | | | | | | |
| Payments for debt extinguishment | — | | | — | | | (24) | | | — | | | (24) | |
| Net distributions to noncontrolling interests from subsidiaries | — | | | (1) | | | — | | | — | | | (1) | |
| Proceeds from issuance of common stock | — | | | — | | | 2 | | | — | | | 2 | |
| Proceeds from issuance of long-term debt | — | | | — | | | 1,833 | | | — | | | 1,833 | |
| Payment of debt issuance costs | — | | | — | | | (33) | | | — | | | (33) | |
| Payments for long-term debt | — | | | (53) | | | (2,432) | | | — | | | (2,485) | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Cash used by continuing operations | (532) | | | (429) | | | (3,047) | | | 2,209 | | | (1,799) | |
| Cash provided by discontinued operations | — | | | 43 | | | — | | | — | | | 43 | |
| Net Cash Used by Financing Activities | (532) | | | (386) | | | (3,047) | | | 2,209 | | | (1,756) | |
| | | | | | | | | |
| Change in cash from discontinued operations | 17 | | | 32 | | | — | | | — | | | 49 | |
| Net Decrease in Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash | (56) | | | (9) | | | (212) | | | — | | | (277) | |
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at Beginning of Period | 95 | | | 38 | | | 480 | | | — | | | 613 | |
| Cash and Cash Equivalents, Funds Deposited by Counterparties and Restricted Cash at End of Period | $ | 39 | | | $ | 29 | | | $ | 268 | | | $ | — | | | $ | 336 | |
(a)All significant intercompany transactions have been eliminated in consolidation
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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 and six months ended June 30, 2020 and 2019. Also refer to NRG's 2019 Form 10-K, which includes detailed discussions of various items impacting the Company's business, results of operations and financial condition, including: Introduction and Overview section; NRG's Business Strategy section; Business section, including how regulation, weather, and other factors affect NRG's business; and Critical Accounting Policies and Estimates section. In addition, refer to the Current Report on Form 8-K filed with the SEC on May 7, 2020, which provides retrospectively revised historical financial information to correspond with the Company's current segment structure.
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.
The Company determined in prior years thatAs you read this discussion and analysis, refer to NRG's Condensed Consolidated Statements of Operations to this Form 10-Q, which present the following businesses were discontinuedresults 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 recast prior periods to present their results in the corporate segment:
•South Central Portfolio
•Carlsbad
•GenOnfinancial 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 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 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. NRG is a customer-driven 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 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 June 30, 2020. NRG was incorporated as a Delaware corporation on May 29, 1992.
As part of perfecting the integrated model, in which the majority of the Company’s generation serves its retail customers, the Company began managing its operations based on the combined results of the retail and wholesale generation businesses with a geographical focus in 2020. As a result, the Company changed its business segments from Retail and Generation to Texas, East and West/Other beginning in the first quarter of 2020. The Company's updated segment structure reflects how management currently makes financial decisions and allocates resources.
The following table summarizes NRG's generation portfolio in MW as of June 30, 2020 by operating segment:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation Type | | Texas | | East | | West/Other (a)(b) | | Total |
| Natural gas | | 4,759 | | | 2,686 | | | 2,308 | | | 9,753 | |
| Coal | | 4,174 | | | 3,140 | | | 605 | | | 7,919 | |
| Oil | | — | | | 3,600 | | | — | | | 3,600 | |
| Nuclear | | 1,132 | | | — | | | — | | | 1,132 | |
| Utility Scale Solar | | — | | | — | | | 321 | | | 321 | |
| Battery Storage & Distributed Solar | | 2 | | | — | | | 60 | | | 62 | |
Total generation capacity (c) | | 10,067 | | | 9,426 | | | 3,294 | | | 22,787 | |
(a) Includes 1,153 MW for the Cottonwood facility that was sold to Cleco on February 4, 2019, which the Company is leasing until 2025
(b) The Distributed Solar figure in West/Other includes the aggregate production capacity of installed and activated residential solar energy systems
(c) All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units
COVID-19
In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declaredAs the COVID-19 outbreak a national emergency. Electricity was deemed a ‘critical and essential business operation’ under various state and federal governmental COVID-19 mandates.
pandemic continues, NRG continues to remainremains 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. In addition, during the second quarter ofDuring 2020, NRG committed $2 millionmigrated a substantial portion of its employees to a remote work environment. The first COVID-19 relief efforts, including funding for urgently needed safety equipment supporting first responders,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 well as funds that aided local communities and teachers.of April 19, 2021. The Company also allocated additional fundingis currently planning to begin returning certain employees to the NRG Employee Relief Fundoffices through a phased approach expected to assist employees adversely impactedbe completed by natural disasters and other extraordinary events.
NRG had activated its Crisis Management Team ("CMT") in January 2020, which proactively began managing the Company's response to the impactsend of COVID-19. The CMT implemented the business continuity plans for the Company and has taken a variety of measures to ensure the ongoing availability of the Company's services, while maintaining the Company's commitment to its core values of health and safety. Pursuant to the Company's Infectious Disease & Pandemic Policy, in March 2020, NRG implemented restrictions on business travel and face-to-face sales channels, instituted remote work practices and enhanced cleaning and hygiene protocols in all of its facilities. During the second quarter of 2020, the Company began to evaluate alternatives for return to normal work operations. In addition, in order to effectively serve the Company’s customers, select essential employees and contractors are continuing to report to plant and certain office locations. The Company requires pre-entry screening, including temperature checks, separation of work crews, additional personal protective equipment for employees and contractors when social distancing cannot be maintained, and a ban on all non-essential visitors. As a result of these business continuity measures, the Company has not experienced any material disruptions in its ability to continue its business operations to date.
The Company continues to utilize the communication protocol established in January 2020, including a central information hub on its intranet, telehealth services, and its Emergency Relief Fund for financially-impacted employees.summer..
While the pandemic may present newpresents risks to the Company's business, as further described in the Company’s 2020 Form 10-K in Part II, Item 1A — —Risk Factors of this Form 10-Q, to the Company’s business,, there was not a material adverse impact on the Company’s 2020 results of operations for the sixthree months ended June 30, 2020.March 31, 2021. NRG believes it has sufficient liquidity on hand to continue business operations.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 $2.2$3.2 billion as of June 30, 2020,March 31, 2021, consisting of cash on hand, and its Revolving Credit Facility.Facility, and additional facilities.
Following the President's declaration of COVID-19 outbreak being a national emergency, the Governors of the majority of states in which the Company operates issued executive orders that every person should, except where necessary to provide or obtain essential services, minimize social gatherings and minimize in-person contact with people who are not in the same household. The impact of these orders closed schools, restaurants and bars, except in certain cases for takeout, and other non-essential businesses. As state restrictions have been eased or lifted, loads have begun to recover in those markets in which the Company operates. The rebound in demand has varied across the Company's market footprint, as restrictions vary regionally. The Company expects demand uncertainty to continue in the near future.
Specifically, in Texas, the PUCT adopted the COVID-19 Electricity Relief Program (“ERP”) to mitigate the impact of COVID-19 on Texas retail electric customers experiencing economic hardship as a result of the pandemic. The COVID-19 ERP
provides temporary disconnection protection for eligible customers and establishes funds to offset some of the costs incurred by retail electric providers to continue service to those customers. Consistent with the PUCT's orders, NRG is also offering deferred payment plans to all residential and small commercial customers while the declaration of emergency in Texas is in place.
The situation surrounding COVID-19 remains fluid and the potential for a material adverse impact on the Company increases the longerexists as long as the virus impacts the level of economic activity in the United States and globally. For this reason,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, andnor 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 outbreak,pandemic, travel restrictions, business and workforce disruptions, any resurgence of the outbreakpandemic and the effectiveness of actions taken to contain, mitigate and treat the disease. See Part II, Item 1A — Risk Factors of this Form 10-Q.
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 served by the Company,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.
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 withchannels; (ii) offering a variety of retail energy products and services, including renewable energy solutions, that are differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs; (ii) offering innovative and renewable energy solutions for customers; (iii) excellence in operating performance of its existing assets; (iv) optimal hedging of NRG's net retail and generation positions;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, limitingwhich seeks to limit global warming in the post-industrial era to a 1.5 degree Celsius increase. Under its new GHG emissions reduction timeline,degrees Celsius. NRG is targeting to achieve a 50% reduction by 2025, from its current 2014 baseline, and net-zero emissions by 2050 from a 2014 baseline.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 20192020 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 17, Regulatory Matters, of this Form 10-Q.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 generatinggeneration 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.
Federal Energy Regulation
D.C. Circuit Ruling on FERC's Use of Tolling Orders — On June 30, 2020, the U.S. Court of Appeals for the D.C. Circuit issued a decision stating that FERC's ability to "toll" actions on rehearing beyond the statutory 30-day period is unlawful. Chairman ChatterjeeState and Commissioner Glick issued a joint statement asking Congress to give FERC a reasonable amount of time to make a decision on rehearing requests under the Natural Gas Act and the Federal Power Act. This decision impacts an array of appeals related to the PJM MOPR order and will impact how rehearings are decided and appeals filed.
StateProvincial Energy Regulation
State Out-Of-Market Subsidy Proposals — NRG has opposed efforts to provide out-of-market subsidies for nuclear generators and intends to continue opposing themProceedings Regarding States’ Participation in the future. Nuclear subsidy programs have either been implemented, are in the process of being implemented, or have been introduced for discussion inWholesale Market — Various states, including Connecticut, Illinois, New Jersey, New York Ohio and Pennsylvania. NRGIllinois, as well as the District of Columbia have initiated proceedings to investigate resource adequacy alternatives and others were unsuccessfulto consider its participation in challenging the legality ofregional wholesale electricity market constructs, specifically withdrawal from the subsidiesregional market or implementing a state-directed capacity procurement regime. Any actions taken by the states could affect market design and market prices in Illinois and New York, and the U.S. Supreme Court has declined to review the lower court decisions. Through NRG's PJM trade organization, it is also currently participating in an appeal of NJBPU's Order regarding ZECs.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.
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 Reforms FilingMonitor Market Seller Offer Cap Complaint — On December 19,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 onin response to a complaint and request for declaratory judgement challenging the pending proposalsstation 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 reform the PJM market to mitigate subsidized resources in the capacity market. FERC directedstate jurisdiction. The order established a Section 206 proceeding and required PJM to applysubmit a filing to show why the Minimum Offer Price Rule, or MOPR, to newstation service netting provisions of its tariff are just and existing resources receiving state subsidiesreasonable. Lawrenceburg Power, LLC filed for rehearing, which was denied by operation of law on November 19, 2020 and subject them to default offer floor prices in their capacity bids. The Order provided for various category specific exemptionsthey subsequently appealed to the MOPR, as well as a unit specific exemption, which permits any resource that can justifyUnited 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 offer lower than the default offer price floor to submit such capacity bids to PJM for review. As part of the December 19, 2019 FERCApril 27, 2021 Order, FERC gave PJM 90 days to make afound 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 submit tariff language to reflect the requirements of the Order and directedrequired PJM to include in this filing a timetable for when it proposes to hold the previously postponed Base Residual Auctions for the 2022/2023 and 2023/2024 delivery years. Multiple parties filed for rehearing and clarification. FERC ruled on April 16, 2020 to largely uphold its December 2019 Order, after which, multiple parties, including NRG, filed for appeal at various circuit courts. On March 18, 2020, PJM made its compliance filing, which among other things, stated that it would hold its next capacity auction six and a half months after a ruling on the compliance filing. Comments to the compliance filing are extended until May 15, 2020. Pursuant to the April 16, 2020 Order, PJM was required to make an additional compliance filing within 4530 days of thatthe Order. PJM made that compliance filing on June 1, 2020 and proposed to (i) hold the previously postponed Base Residual Auction for the 2022/2023 deliver year six and a half months after FERC issues an Order to (ii) hold the additional outstanding auctions four and half months after the 2022/2023 auction is held. Subjecting subsidized resources to default offer floors in the capacity market should protect the market from further price suppression. The impact of these changes on capacity markets outcomes depends on, among other factors, bidding behavior, load forecast changes, new resource entry, and existing resource exit.
New Jersey Board of Public Utilities’ Investigation on Resource Adequacy Alternatives — On March 25, 2020, the NJBPU initiated a proceeding to investigate resource adequacy alternatives for New Jersey. NRG submitted initial comments on May 20, 2020, and subsequently filed reply comments on June 24, 2020. On September 18, 2020, the NJBPU will hold a technical conference. The proceeding is pending. Any actions taken by the NJBPUThis decision could affect market prices in PJM.the rates that plants pay for station power.
New England
ISO-NE Inventoried Energy Compensation Proposal — On March 25, 2019, ISO-NE proposed an interim measure to address near-term fuel security concerns. On August 6, 2019, FERC issued a notice stating that due to lack of quorum, ISO-NE's proposal became effective by operation of law. Multiple parties filed for rehearing. Those rehearings were denied. Subsequently, multiple parties filed an appeal of FERC's Order to the Court of Appeals for the D.C. Circuit. On April 14, 2020, FERC filed a motion for a voluntary remand. On April 21, 2020, the Court of Appeals for the D.C. Circuit remanded the case back to FERC. On June 18, 2020, FERC issued an order accepting the Inventoried Energy Compensation Proposal. ISO-NE's proposal will affect future capacity market prices and the compensation that fuel secure units receive.
ISO-NE Fuel Security Improvements Proposal — On April 15, 2020, ISO-NE filed a compliance filing proposing improvements to the wholesale market design to address winter fuel security issues as directed by FERC. Multiple parties filed comments and protests. The matter is pending at FERC. The outcome of the matter will affect market prices in ISO-NE.
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 REPrequest for proposal to address the retirements of Mystic Units 8 and 9. NRG, through its trade associations, filed comments on June 30, 2020. The outcome of this proceeding could affect the retirement of the Mystic Units 8 and 9, thereby affecting capacity prices in ISO-NE.
Paper Hearing on ISO-NE's New Entrant Rule — On July 1,August 17, 2020, FERC issued an order establishingdenying the complaint. After a Section 206 hearing initiatedrehearing that was denied by FERC'soperation 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 finding thatnature of the "new entrant rules" may be unjustlegislation and unreasonable, specifically asrulemaking process, it is unclear what, if any, impact these proposals would have on the Company or the ERCOT wholesale market.
relates to the seven-year price-lock rule. This order is a result of the D.C. Circuit February 2, 2018 remand of a FERC order regarding how generators that previously received a seven-year "price lock" should be priced in future auctions. The price-lock mechanism permits qualified new resources that clear the auction to receive their first-year clearing price for seven years. Because several auctions have been held under the existing rules, any subsequent order from FERC could affect future capacity prices in ISO-NE, as well as affect the price that non-price locked resources could receive from prior capacity auctions.
New York
New York State Public Service Commission Retail Energy Market Proceedings — On February 23, 2016, the NYSPSC issued an order referred to as the Retail Reset Order. Among other things, the Retail Reset Order placed a price cap on energy supply offers and imposed burdensome new regulations on customers. Various parties have challenged the NYSPSC's authority to regulate prices charged by competitive suppliers. On May 9, 2019 the New York Court of Appeals, the state’s highest tribunal, issued a decision affirming the NYSPSC’s authority to regulate ESCO’s prices as a condition of access to the utilities’ infrastructure. In conjunction with the court challenge, the NYSPSC also noticed an evidentiary proceeding. On December 12, 2019, the NYSPSC issued an order adopting changes to the retail access energy market based on the record in the evidentiary proceeding. The Order limits ESCO offers to three compliant products: guaranteed savings from the utility default rate, a fixed term capped at 5% of the rolling 12-month average utility default rate, or NY-sourced renewable energy that is at least 50% greater than the prevailing NY Renewable Energy Standard for load serving entities. The Order also establishes new ESCO eligibility criteria and certification process, as well as re-certification of current ESCOs. The NYSPSC ordered compliance effective February 10, 2020. On January 13, 2020, multiple parties filed motions for rehearing and a stay of the Order. On March 2, 2020, the NYSPSC issued a notice seeking comments by April 13, 2020 on the petitions for rehearing. NRG has been granted multiple extensions, resulting in the current effective date of October 9, 2020 to meet the compliance requirements for its retail products. The limited offerings imposed by the Order, as issued, may negatively impact the Company's retail sales in New York.
New York State Public Service Commission Resource Adequacy Proceeding — On August 8, 2019, the NYSPSC established an investigation into New York's resource adequacy market design. On November 8, 2019, NRG filed comments and recommendations, specifically putting forth NRG's Forward Clean Energy Market Proposal, that would allow New York to maintain a reliable system while advancing its environmental goals. The NYSPSC has engaged The Brattle Group to evaluate the multiple alternative resource adequacy structures that were recommended by the parties in the proceeding. The NYSPSC held a technical conference on July 10, 2020. The proceeding is pending. Any actions taken by the NYSPSC could affect market design and market prices in New York.
New York Buyer Side Mitigation Proceedings — On February 20, 2020, FERC issued multiple orders pertaining to the NYISO capacity market. The orders narrowed certain exemptions to buyer side mitigation measures. Specifically, FERC stated that certain renewable and self-supply resources would be exempt from offer floor mitigation but rejected NYISO’s proposal of a 1,000 MW cap on renewable resources that could qualify for the exemption. FERC ordered NYISO to make a compliance filing narrowly tailoring its cap. On April 7, 2020, NYISO submitted its compliance filing proposing a formula that sets the Renewable Exemption Limit based generally on projected load growth and generator requirements. On April 28, 2020, the generator trade association filed comments seeking clarification related to the Renewable Exemption Limit formula. On July 16, 2020, FERC accepted a large part of NYISO's April compliance filing. FERC also rejected a complaint to exempt new electric storage resources. It also rejected a blanket exemption to demand response providers currently subject to mitigation but granted a request for new demand response to receive a blanket exemption from the buyer side mitigation measures. On June 18, 2020, the NYSPSC filed petitions for review with the D.C. Circuit regarding these buyer side mitigation orders. Implementation of buyer side mitigation measures to address price suppression provides more accurate capacity price signals in the competitive market.
Texas
ORDC Reforms — In January 2019, the PUCT directed ERCOT to implement changes to its scarcity pricing structure, known as the ORDC, which is designed to increase the likelihood of scarcity pricing to support existing generation and new investment. The PUCT directed ORDC reforms to be implemented in two phases of gradually increasing magnitude. The first phase became effective on March 1, 2019 and the second phase was put into effect on March 1, 2020. To date, the ORDC reforms have produced a noticeable improvement in scarcity pricing.
Public Utility Commission of Texas’ Actions Relatedwith Respect to COVID-19 — Winter Storm Uri
On March 26, 2020,February 15, 2021, the PUCT adoptedissued an emergency order that required the COVID-19 Electricity Relief Programenergy 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 ("ERP"EEA3") aimed to mitigateconditions, as directed by ERCOT. This action effectively set the impactprice of COVID-19 on residential customersenergy at $9,000 per megawatt-hour for the duration of the EEA3 event. Additionally, in the competitive retail electric market who are experiencing economic hardship as a resultsame 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 pandemic. The COVID-19 ERP protects residential customers deemed eligible byERCOT market above $9,000 per megawatt-hour. On February 16, 2021, the PUCT’s third party administratorPUCT 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 disconnection for nonpayment untillate February 15, 2021 to early February 19, 2021, when ERCOT declared the end of August 2020, unless extended by the PUCT. The COVID-19 ERP also establishes anEEA3 conditions terminated.
On February 21, 2021, citing a public emergency fund to allow Retail Electric Providers ("REPs") to recover a certain amount of credit losses incurred while continuing to serve these customers. REPs may recover from the fund a proxy for a portion of their costs (at a fixed rate of $0.04 per kWh) related to
eligible residential customers with an unpaid, past due electric bill subject to a disconnection for non-payment notice. On March 26, 2020,and imperative public necessity, the PUCT issued an order that required REPsdirecting retail electricity providers ("REP") to suspend charginglate fees and prohibiting REPs from disconnecting residential and small commercial customers for non-payment. Although the late feesfee 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
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 response to the Governor's disaster declaration relating to COVID-19. On April 17, 2020, the PUCT narrowed the scopeimplementation of the late fees waiver to just residential customers. The late fees waiver ended on May 15, 2020.
CAISO
Resource Adequacy Central Procurement Proceeding — On March 26, 2020, a CPUC Administrative Law Judge issued a proposed decision adopting implementation details for the central procurement of multi-year local resource adequacy capacity to begin for the 2023 compliance year for the PG&E and Southern California Edison ("SCE") service areas, under which PG&E and SCE would be the respective central procurement entities. The March 26, 2020 proposed decision declined to adopt a central procurement framework for the San Diego Gas and Electric service area and rejected a proposed settlement filed by various entities including NRG, which included the expansion of multi-year requirements to all categories of resource adequacy (system, flexible and local) and a residual procurement model for the central procurement entity. NRG submitted comments opposing the proposed decision on April 15, 2020. On June 11, 2020, the CPUC adopted the decision mandating the central procurement of multi-year local resource adequacy capacity to begin for the 2023 compliance year for PG&E and SCE service areas. The CPUC also rejected the proposed settlement filed by various entities, including NRG. The CPUC decision represents a retreat from market-based solutions ensuring reliable capacity in California.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 may affect the Company are under reviewhave 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 20192020 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 Statementscondensed 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 SO2, ozone, and PM2.5. Many of the Company's facilities are located in or near areas that are
classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS havemay 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.
Clean Power PlanCPP/ACE Rules — The attention in recent years on GHG emissions has resulted in federal regulations and state legislative and regulatory action.regulations. In October 2015, the EPA finalizedpromulgated the CPP, addressing GHG emissions from existing EGUs. On February 9, 2016, the U.S. Supreme Court stayed the CPP. In July 2019, EPA promulgated the ACE rule, which rescinded the CPP, which had sought to broadly regulate CO2 emissions from the power sector. The ACE rule requires states that have coal-fired EGUs to develop plans to seek heat rate improvements from coal-fired EGUs. Texas, Illinois and Delaware have started working on plans to comply withOn January 19, 2021, the ACE rule. Numerous parties have challengedD.C. Circuit vacated the ACE rule in(but on February 22, 2021, at the D.C. Circuit and numerous parties have filed petitions for reconsideration withEPA's request, stayed the EPA.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.
On August 14, In 2019 the EPA proposed targeted changes to the April 2015 Rule including changes to address the August 2018 D.C. Circuit decision. On December 2, 2019, the EPA released for comment "Closure Part A Proposal" to revise the CCR Rule to address the D.C. Circuit's 2018 decision regarding the adequacy of clay-lined impoundments, obligations to close all unlined impoundments and related deadlines. On February 20, 2020, the EPA proposed the framework for developing and implementing a federal permit program for states that are not approvedseveral changes to administer the CCRthis rule. On March 3,August 28, 2020, the EPA proposed for comment "A Holistic Approach to Closure Part B," which proposes procedures for obtaining approval to operate existing impoundments with alternative liners. On July 29, 2020, the EPA released a prepublication (non-official) version of the final rulefinalized "A Holistic Approach to Closure Part A: Deadline to Initiate Closure," which when published in the Federal Register will amendamended 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 anticipates that the EPA will promulgate additional regulations to further amend the existing rule. The Company will updatehas updated its estimates of required environmental capital expenditures as the rule is revised.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.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 twicethree times through addendums to cover payments through December 31, 2019. The Department of Justice has proposed to extend the existing settlement for three additional years through December 31, 2022. STPNOC has agreed to this proposal and steps to obtain approval of the settlement by the authorized representative of the Attorney General are in progress. 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 would have 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, postponespostponed the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA completes its next rulemaking.amended the rule. On April 12, 2019, the United States Court of Appeals for the Fifth circuit addressed challenges to the rule brought by several environmental groups related to legacy wastewaters and coal ash leachate and remanded portions of the rule to the EPA. On November 22, 2019,October 13, 2020, the EPA proposed amendingamended the 2015 ELG rule by: (x) decreasing(i) altering the stringency of the selenium limit (but increasing the stringency of the nitrate and mercury limits)certain limits for FGD wastewater; (y)(ii) relaxing the zero-discharge requirement for bottom ash transport water; and (z)(iii) changing several deadlines. The Company has eliminated its estimateis in the process of estimating the environmental capital expenditures that was anticipated.will be required to comply. The Companycapital expenditures required to comply will revisitdepend on elections regarding future operations of each coal-fired unit. NRG expects to make these estimates afterelections for each unit in the fourth quarter of 2021 at which time the EPA revises the rule andwill be notified as permits are renewed.required. Accordingly, we do not expect to provide estimates of ELG compliance costs until early 2022.
Regional Environmental Developments
NY NOx — On December 31, 2019, the New York State Department of Environmental Conservation finalized a more stringent NOx regulation that will result in the retirement of the Company's combustion turbines in Astoria, New York in 2023.
Ash Regulation in Illinois — On July 30, 2019, Illinois enacted legislation that will requirerequires the state to promulgate regulations regarding coal ash at surface impoundments. On March 30, 2020,April 15, 2021, the state releasedpromulgated the implementing regulation, which became effective on April 21, 2021. The new regulation requires NRG to apply for initial operating permits for its proposed implementing regulations. The Company expects the state to promulgate the final implementing regulationscoal ash surface impoundments by October 31, 2021 and construction permits (for closure) starting in March 2021, at which time regulated entities will then prepare and submit permit applications.2022.
Significant Events
The following significant events have occurred during 20202021 as further described within this Management's Discussion and Analysis and the Condensed Consolidated Financial Statements: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 July 24, 2020,January 5, 2021, the Company entered into a definitive purchase agreement with Centrica to acquireacquired Direct Energy, a North American subsidiary of Centrica (the "Purchase Agreement").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 68 Canadian provinces. The acquisition will addincreases NRG's retail portfolio by over 3 million customers to NRG's business and build on and complementcomplements its integrated model, enabling better matching of power generation with customer demand.model. It will also broadenbroadens 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 will paypaid an aggregate purchase price of $3.6$3.625 billion in cash subject to aand an initial purchase price adjustment including a working capital adjustment.of $77 million. The Company expects to fundfunded 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 $2.4$2.9 billion in newly-issued secured and unsecured corporate debt and approximately $750 millionissued in convertible preferred stock or other equity-linked instruments.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 expects to increaseincreased its collective liquidity and collateral facilities by $3.5$3.4 billion through a combination of new letter of credit facilities and increase to the existingamending its Revolving Credit Facility.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.
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 acquisitiontransaction is expected to close in the fourth quarter of 2021, and is subject to approval by the shareholders of Centrica, as well as customaryvarious closing conditions, approvals and consents, including FERC, NYSPSC, and regulatory approvals, including the expiration or termination of the applicable waiting periodantitrust review under the HSR Act, and the receipt of approvals or expiration of applicable waiting periods under the Federal Power Act and the Canadian CompetitionHart-Scott-Rodino Act.
The acquisition is targeted to close by December 31, 2020. There are no assurances that the conditions to the consummation of the acquisition of Direct Energy will be satisfied, that Centrica will not seek or enter into an alternative transaction, or that the acquisition of Direct Energy will be consummated on the terms agreed to, or at all.
Share Repurchases
During the six months ended June 30, 2020, the Company completed $224 million of share repurchases at an average price of $33.05 per share, including $27 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuance.
Renewable Power Purchase Agreements
During 2019, NRG began execution of itsThe Company's strategy is to procure mid to long-term generation through renewable power purchase agreements. As of June 30, 2020,March 31, 2021, NRG has entered into PPAs totaling approximately 1,600 MWs2.2 GW with third-party project developers and other counterparties. The tenor of these agreements is an average of elevenbetween 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,
For discussion certain of COVID-19 related considerations, referthese PPA contracts have been amended to Management’s Discussion and Analysisallow for the delay of Financial Condition and Results of Operations – Executive Summary and Liquidity and Capital Resources.
Midwest Generation Lease Purchase
On July 22, 2020, Midwest Generation signed purchase agreements to acquire all of the ownership interests in the Powerton facility and Units 7 and 8 of the Joliet facility, which were being leased through 2034 and 2030, respectively,project completion dates from mid-2021 into 2022. These amendments include improved terms for approximately $260 million. The Company intends to fund the purchase with borrowings under its Revolving Credit Facility in an amount equal to the existing operating lease liabilities of $148 million as of June 30, 2020 and the remainder from cash-on-hand. The closing is conditioned, among other items, on the receipt of regulatory approvals from FERC and under the HSR Act. Upon closing, lease expense related to these facilities, which totaled approximately $14 million in 2019, will be eliminated.
Trends Affecting Results of Operations and Future Business Performance
The Company’s trends are described in the Company’s 20192020 Form 10-K in Item 7, Management’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.
Consolidated Results of Operations
The following table provides selected financial information for the Company:
| | | | Three months ended June 30, | | | Six months ended June 30, | | | Three months ended March 31, | |
| (In millions, except as otherwise noted) | (In millions, except as otherwise noted) | 2020 | | 2019 | | Change | | 2020 | | 2019 | | Change | (In millions, except as otherwise noted) | 2021 | | 2020 | | Change | |
| Operating Revenues | Operating Revenues | | | | | | | | | | | | Operating Revenues | | | | | | |
| Retail revenue | Retail revenue | $ | 1,832 | | | $ | 1,685 | | | $ | 147 | | | $ | 3,493 | | | $ | 3,274 | | | $ | 219 | | Retail revenue | $ | 6,162 | | | $ | 1,661 | | | $ | 4,501 | | |
Energy revenue(a) | Energy revenue(a) | 83 | | | 236 | | | (153) | | | 207 | | | 526 | | | (319) | | Energy revenue(a) | 482 | | | 124 | | | 358 | | |
Capacity revenue(a) | Capacity revenue(a) | 195 | | | 201 | | | (6) | | | 344 | | | 357 | | | (13) | | Capacity revenue(a) | 155 | | | 149 | | | 6 | | |
| Mark-to-market for economic hedging activities | Mark-to-market for economic hedging activities | 43 | | | 241 | | | (198) | | | 39 | | | 261 | | | (222) | | Mark-to-market for economic hedging activities | (32) | | | (4) | | | (28) | | |
| Other revenues (a)(b) | Other revenues (a)(b) | 85 | | | 102 | | | (17) | | | 174 | | | 212 | | | (38) | | Other revenues(a)(b) | 1,324 | | | 89 | | | 1,235 | | |
| Total operating revenues | Total operating revenues | 2,238 | | | 2,465 | | | (227) | | | 4,257 | | | 4,630 | | | (373) | | Total operating revenues | 8,091 | | | 2,019 | | | 6,072 | | |
| Operating Costs and Expenses | Operating Costs and Expenses | | | | | | | | | | | | Operating Costs and Expenses | | | | | | |
Cost of Sales (c) | Cost of Sales (c) | 1,135 | | | 1,273 | | | 138 | | | 2,284 | | | 2,614 | | | 330 | | Cost of Sales (c) | 7,183 | | | 1,149 | | | (6,034) | | |
| Mark-to-market for economic hedging activities | Mark-to-market for economic hedging activities | (44) | | | 220 | | | 264 | | | (92) | | | 220 | | | 312 | | Mark-to-market for economic hedging activities | (753) | | | (48) | | | 705 | | |
Contract and emissions credit amortization (c) | Contract and emissions credit amortization (c) | 1 | | | 6 | | | 5 | | | 2 | | | 11 | | | 9 | | Contract and emissions credit amortization (c) | 1 | | | 1 | | | — | | |
| Operations and maintenance | Operations and maintenance | 279 | | | 284 | | | 5 | | | 572 | | | 531 | | | (41) | | Operations and maintenance | 352 | | | 293 | | | (59) | | |
| Other cost of operations | Other cost of operations | 63 | | | 62 | | | (1) | | | 125 | | | 120 | | | (5) | | Other cost of operations | 81 | | | 62 | | | (19) | | |
| Total cost of operations | Total cost of operations | 1,434 | | | 1,845 | | | 411 | | | 2,891 | | | 3,496 | | | 605 | | Total cost of operations | 6,864 | | | 1,457 | | | (5,407) | | |
| Depreciation and amortization | Depreciation and amortization | 110 | | | 85 | | | (25) | | | 219 | | | 170 | | | (49) | | Depreciation and amortization | 317 | | | 109 | | | (208) | | |
| Impairment losses | — | | | 1 | | | 1 | | | — | | | 1 | | | 1 | | |
| | Selling, general and administrative costs | Selling, general and administrative costs | 208 | | | 211 | | | 3 | | | 417 | | | 405 | | | (12) | | Selling, general and administrative costs | 330 | | | 190 | | | (140) | | |
| Reorganization costs | — | | | 2 | | | 2 | | | 3 | | | 15 | | | 12 | | |
| Development costs | 2 | | | 2 | | | — | | | 5 | | | 4 | | | (1) | | |
| Provision for credit losses | | Provision for credit losses | 611 | | | 24 | | | (587) | | |
| Acquisition-related transaction and integration costs | | Acquisition-related transaction and integration costs | 42 | | | 1 | | | (41) | | |
| Total operating costs and expenses | Total operating costs and expenses | 1,754 | | | 2,146 | | | 392 | | | 3,535 | | | 4,091 | | | 556 | | Total operating costs and expenses | 8,164 | | | 1,781 | | | (6,383) | | |
| | Gain on sale of assets | Gain on sale of assets | — | | | 1 | | | (1) | | | 6 | | | 2 | | | 4 | | Gain on sale of assets | 17 | | | 6 | | | 11 | | |
| Operating Income | 484 | | | 320 | | | 164 | | | 728 | | | 541 | | | 187 | | |
| Other Income/(Expense) | | | | | | | | | | | | |
| Equity in earnings/(losses) of unconsolidated affiliates | 12 | | | — | | | 12 | | | 1 | | | (21) | | | 22 | | |
| Operating (Loss)/Income | | Operating (Loss)/Income | (56) | | | 244 | | | (300) | | |
| Other (Expense)/Income | | Other (Expense)/Income | | | | | | |
| Equity in losses of unconsolidated affiliates | | Equity in losses of unconsolidated affiliates | (6) | | | (11) | | | 5 | | |
| Impairment losses on investments | Impairment losses on investments | — | | | — | | | — | | | (18) | | | — | | | (18) | | Impairment losses on investments | — | | | (18) | | | 18 | | |
| Other income, net | Other income, net | 14 | | | 20 | | | (6) | | | 41 | | | 32 | | | 9 | | Other income, net | 22 | | | 27 | | | (5) | | |
| Loss on debt extinguishment, net | — | | | (47) | | | 47 | | | (1) | | | (47) | | | 46 | | |
| | Interest expense | Interest expense | (96) | | | (105) | | | 9 | | | (193) | | | (219) | | | 26 | | Interest expense | (127) | | | (98) | | | (29) | | |
| Total other expense | Total other expense | (70) | | | (132) | | | 62 | | | (170) | | | (255) | | | 85 | | Total other expense | (111) | | | (100) | | | (11) | | |
| Income from Continuing Operations Before Income Taxes | 414 | | | 188 | | | 226 | | | 558 | | | 286 | | | 272 | | |
| Income tax expense/(benefit) | 101 | | | (1) | | | (102) | | | 124 | | | 3 | | | (121) | | |
| Income from Continuing Operations | 313 | | | 189 | | | 124 | | | 434 | | | 283 | | | 151 | | |
| (Loss)/Income Before Income Taxes | | (Loss)/Income Before Income Taxes | (167) | | | 144 | | | (311) | | |
| Income tax (benefit)/expense | | Income tax (benefit)/expense | (85) | | | 23 | | | 108 | | |
| | Income from discontinued operations, net of income tax | — | | | 13 | | | (13) | | | — | | | 401 | | | (401) | | |
| Net Income | 313 | | | 202 | | | 111 | | | 434 | | | 684 | | | (250) | | |
| Less: Net income attributable to redeemable noncontrolling interests | — | | | 1 | | | (1) | | | — | | | 1 | | | (1) | | |
| Net Income Attributable to NRG Energy, Inc. | $ | 313 | | | $ | 201 | | | $ | 112 | | | $ | 434 | | | $ | 683 | | | $ | (249) | | |
| | Net (Loss)/Income | | Net (Loss)/Income | $ | (82) | | | $ | 121 | | | $ | (203) | | |
| | Business Metrics | Business Metrics | | | | | | | | | | | | Business Metrics | | | | | | |
| Average natural gas price — Henry Hub ($/MMBtu) | Average natural gas price — Henry Hub ($/MMBtu) | $ | 1.72 | | | $ | 2.64 | | | (35) | % | | $ | 1.83 | | | $ | 2.89 | | | (37) | % | 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 SO2 and NOx credits and excludes amortization of RGGI credits
Management’s discussion of the results of operations for the three months ended June 30,March 31, 2021 and 2020 and 2019
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 June 30, 2020March 31, 2021 and 2019.2020. The average on-peak power prices decreased across all regionsincreased significantly in Texas due to mild winter weatherthe impact from Winter Storm Uri. East and lower demandWest/Other on-peak power prices increased due to COVID-19.higher gas prices, especially in February and March, driven by cold winter weather.
| | | | Average on Peak Power Price ($/MWh) | | | Average on Peak Power Price ($/MWh) |
| | Three months ended June 30, | | | Three months ended March 31, |
| Region | Region | 2020 | | 2019 | | Change % | Region | 2021 | | 2020 | | Change % |
| Texas | Texas | | | | | | Texas | | | | | |
ERCOT - Houston(a) | ERCOT - Houston(a) | $ | 24.34 | | | $ | 31.88 | | | (24) | % | ERCOT - Houston(a) | $ | 619.94 | | | $ | 25.33 | | | 2,347 | % |
ERCOT - North(a) | ERCOT - North(a) | 20.03 | | | 30.13 | | | (34) | % | ERCOT - North(a) | 621.04 | | | 24.43 | | | 2,442 | % |
| | East | East | | East | |
NY J/NYC(b) | NY J/NYC(b) | $ | 19.01 | | | $ | 29.52 | | | (36) | % | NY J/NYC(b) | $ | 47.71 | | | $ | 23.83 | | | 100 | % |
NEPOOL(b) | NEPOOL(b) | 20.25 | | | 27.15 | | | (25) | % | NEPOOL(b) | 55.26 | | | 24.61 | | | 125 | % |
COMED (PJM)(b) | COMED (PJM)(b) | 19.28 | | | 26.78 | | | (28) | % | COMED (PJM)(b) | 33.51 | | | 21.29 | | | 57 | % |
PJM West Hub(b) | PJM West Hub(b) | 20.79 | | | 28.54 | | | (27) | % | PJM West Hub(b) | 35.09 | | | 22.47 | | | 56 | % |
| West | | |
| West/Other | | West/Other | |
MISO - Louisiana Hub(b) | MISO - Louisiana Hub(b) | $ | 22.06 | | | $ | 33.40 | | | (34) | % | MISO - Louisiana Hub(b) | $ | 40.70 | | | $ | 22.14 | | | 84 | % |
CAISO - SP15(b) | CAISO - SP15(b) | 19.21 | | | 23.30 | | | (18) | % | 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 June 30, 2020March 31, 2021 and 2019:2020:
| | | | Average Realized Power Price ($/MWh) | | | Average Realized Power Price ($/MWh) |
| | Three months ended June 30, | | | Three months ended March 31, |
| Region | Region | 2020 | | 2019 | | Change % | Region | 2021 | | 2020 | | Change % |
East(a) | East(a) | $ | 28.41 | | | $ | 31.91 | | | (11) | % | East(a) | $ | 41.29 | | | $ | 40.63 | | | 2 | % |
| West/Other | West/Other | 27.45 | | | 33.29 | | | (18) | % | 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 $12.99/$2.47/MWh in the three months ended June 30, 2020March 31, 2021 and $5.95/$22.88/MWh in the three months ended June 30, 2019 March 31, 2020
The average realized power prices decreasedincreased in West/Other for the three months ended June 30, 2020March 31, 2021 as compared to the same period in 20192020 due to lower power andhigher electricity prices as a result of increased natural gas prices.
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.
The below tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended June 30, 2020March 31, 2021 and 2019:2020:
| | | Three months ended June 30, 2020 | | | Three months ended March 31, 2021 |
| ($ In millions) | ($ In millions) | Texas | | East | | West/Other | | | Corporate/Eliminations | | Total | ($ In millions) | Texas | | East | | West/Services/Other | | | Corporate/Eliminations | | Total |
| Retail revenue | Retail revenue | $ | 1,521 | | | $ | 311 | | | $ | — | | | | $ | — | | | $ | 1,832 | | Retail revenue | $ | 2,114 | | | $ | 3,543 | | | $ | 505 | | | | $ | — | | | $ | 6,162 | |
| Energy revenue | Energy revenue | 5 | | | 19 | | | 60 | | | | (1) | | | 83 | | Energy revenue | 285 | | | 126 | | | 70 | | | | 1 | | | 482 | |
| Capacity revenue | Capacity revenue | — | | | 179 | | | 16 | | | | — | | | 195 | | Capacity revenue | — | | | 141 | | | 14 | | | | — | | | 155 | |
| Mark-to-market for economic hedging activities | Mark-to-market for economic hedging activities | — | | | 40 | | | 1 | | | | 2 | | | 43 | | Mark-to-market for economic hedging activities | (1) | | | (4) | | | (28) | | | | 1 | | | (32) | |
| Other revenue | Other revenue | 52 | | | 17 | | | 17 | | | | (1) | | | 85 | | Other revenue | 1,304 | | | 19 | | | 4 | | | | (3) | | | 1,324 | |
| Operating revenue | Operating revenue | 1,578 | | | 566 | | | 94 | | | | — | | | 2,238 | | Operating revenue | 3,702 | | | 3,825 | | | 565 | | | | (1) | | | 8,091 | |
| Cost of fuel | Cost of fuel | (123) | | | (19) | | | (30) | | | | — | | | (172) | | Cost of fuel | (724) | | | (18) | | | (25) | | | | — | | | (767) | |
| Purchased power | Purchased power | (203) | | | (97) | | | (3) | | | | 3 | | | (300) | | Purchased power | (986) | | | (2,509) | | | (172) | | | | — | | | (3,667) | |
Other cost of sales(b)(c) | Other cost of sales(b)(c) | (554) | | | (98) | | | (10) | | | | (1) | | | (663) | | Other cost of sales(b)(c) | (1,896) | | | (594) | | | (259) | | | | — | | | (2,749) | |
| Mark-to-market for economic hedging activities | Mark-to-market for economic hedging activities | 41 | | | 5 | | | — | | | | (2) | | | 44 | | Mark-to-market for economic hedging activities | 525 | | | 166 | | | 63 | | | | (1) | | | 753 | |
| Contract and emission credit amortization | Contract and emission credit amortization | (1) | | | — | | | — | | | | — | | | (1) | | Contract and emission credit amortization | (1) | | | — | | | — | | | | — | | | (1) | |
| Gross margin | Gross margin | $ | 738 | | | $ | 357 | | | $ | 51 | | | | $ | — | | | $ | 1,146 | | Gross margin | $ | 620 | | | $ | 870 | | | $ | 172 | | | | $ | (2) | | | $ | 1,660 | |
| Less: Mark-to-market for economic hedging activities, net | Less: Mark-to-market for economic hedging activities, net | 41 | | | 45 | | | 1 | | | | — | | | 87 | | Less: Mark-to-market for economic hedging activities, net | 524 | | | 162 | | | 35 | | | | — | | | 721 | |
| Less: Contract and emission credit amortization, net | Less: Contract and emission credit amortization, net | (1) | | | — | | | — | | | | — | | | (1) | | Less: Contract and emission credit amortization, net | (1) | | | — | | | — | | | | — | | | (1) | |
| Economic gross margin | Economic gross margin | $ | 698 | | | $ | 312 | | | $ | 50 | | | | $ | — | | | $ | 1,060 | | Economic gross margin | $ | 97 | | | $ | 708 | | | $ | 137 | | | | $ | (2) | | | $ | 940 | |
(a) Includes capacity and emissions credits | | |
(b) Includes $485 million and $3 million of TDSP expense in Texas and East, respectively | | | | | |
| (a) Includes trading gains and losses and ancillary revenues | | (a) Includes trading gains and losses and ancillary revenues | | | |
| (b) Includes capacity and emissions credits | | (b) Includes capacity and emissions credits |
| (c) Includes $590 million and $38 million of TDSP expense in Texas and East, respectively | | (c) Includes $590 million and $38 million of TDSP expense in Texas and East, respectively | | | |
| Business Metrics | Business Metrics | | | | Business Metrics | | | |
| Mass Market electricity sales volume (GWh) | 9,763 | | | 2,355 | | | — | | | | | 12,118 | | |
| C&I electricity sales volume (GWh) | 4,213 | | | 365 | | | — | | | | | 4,578 | | |
| Natural gas sales volume (MDth) | — | | | 3,591 | | | — | | | | | 3,591 | | |
| Average retail Mass Market customer count (in thousands) | 2,442 | | | 1,190 | | | — | | | | | 3,632 | | |
| Ending retail Mass Market customer count (in thousands) | 2,447 | | | 1,171 | | | — | | | | | 3,618 | | |
| Home electricity sales volume (GWh) | | Home electricity sales volume (GWh) | 10,186 | | | 4,076 | | | 320 | | | | | 14,582 | |
| Business electricity sales volume (GWh) | | Business electricity sales volume (GWh) | 6,524 | | | 13,838 | | | 630 | | | | | 20,992 | |
| Home natural gas sales volume (MDth) | | Home natural gas sales volume (MDth) | — | | | 42,434 | | | 35,696 | | | | | 78,130 | |
| Business natural gas sales volume (MDth) | | Business natural gas sales volume (MDth) | — | | | 264,588 | | | — | | | | | 264,588 | |
Average retail Home customer count (in thousands) (a) | | Average retail Home customer count (in thousands) (a) | 3,082 | | | 1,947 | | | 552 | | | | | 5,581 | |
Ending retail Home customer count (in thousands) (a) | | Ending retail Home customer count (in thousands) (a) | 3,086 | | | 2,042 | | | 553 | | | | | 5,681 | |
| GWh sold | GWh sold | 7,565 | | | 1,232 | | | 2,186 | | | | | 10,983 | | GWh sold | 7,349 | | | 3,245 | | | 2,029 | | | | | 12,623 | |
GWh generated:(a) | | | | |
GWh generated:(b) | | GWh generated:(b) | | | |
| Coal | Coal | 3,777 | | | 59 | | | — | | | | | 3,836 | | Coal | 3,840 | | | 1,301 | | | — | | | | | 5,141 | |
| Gas | Gas | 1,341 | | | 479 | | | 2,246 | | | | | 4,066 | | Gas | 1,185 | | | 107 | | | 1,985 | | | | | 3,277 | |
| Nuclear | Nuclear | 2,260 | | | — | | | — | | | | | 2,260 | | Nuclear | 2,324 | | | — | | | — | | | | | 2,324 | |
| Oil | Oil | — | | | 66 | | | — | | | | | 66 | | Oil | — | | | 17 | | | — | | | | | 17 | |
| | Total | Total | 7,378 | | | 604 | | | 2,246 | | | | | 10,228 | | Total | 7,349 | | | 1,425 | | | 1,985 | | | | | 10,759 | |
(a) Includes owned and leased generation, and excludes equity investments | | | | |
| (a) Home customer count includes recurring residential and small commercial customers, including municipal aggregations | | (a) Home customer count includes recurring residential and small commercial customers, including municipal aggregations | | | |
| (b) Includes owned and leased generation, and excludes equity investments | | (b) Includes owned and leased generation, and excludes equity investments | | | |
| | | Three months ended June 30, 2019 | | | Three months ended March 31, 2020 |
| ($ In millions) | ($ In millions) | Texas | | East | | West/Other | | | Corporate/Eliminations | | Total | ($ In millions) | Texas | | East | | West/Services/Other | | | Corporate/Eliminations | | Total |
| Retail revenue | Retail revenue | $ | 1,433 | | | $ | 253 | | | $ | — | | | | $ | (1) | | | $ | 1,685 | | Retail revenue | $ | 1,292 | | | $ | 352 | | | $ | 18 | | | | $ | (1) | | | $ | 1,661 | |
| Energy revenue | Energy revenue | 136 | | | 48 | | | 52 | | | | — | | | 236 | | Energy revenue | 5 | | | 45 | | | 75 | | | | (1) | | | 124 | |
| Capacity revenue | Capacity revenue | — | | | 195 | | | 6 | | | | — | | | 201 | | Capacity revenue | — | | | 134 | | | 15 | | | | — | | | 149 | |
| Mark-to-market for economic hedging activities | Mark-to-market for economic hedging activities | 210 | | | 16 | | | 16 | | | | (1) | | | 241 | | Mark-to-market for economic hedging activities | — | | | (20) | | | 15 | | | | 1 | | | (4) | |
| | Other revenue | Other revenue | 58 | | | 12 | | | 32 | | | | — | | | 102 | | Other revenue | 61 | | | 10 | | | 20 | | | | (2) | | | 89 | |
| Operating revenue | Operating revenue | 1,837 | | | 524 | | | 106 | | | | (2) | | | 2,465 | | Operating revenue | 1,358 | | | 521 | | | 143 | | | | (3) | | | 2,019 | |
| Cost of fuel | Cost of fuel | (200) | | | (34) | | | (32) | | | | — | | | (266) | | Cost of fuel | (103) | | | (55) | | | (36) | | | | — | | | (194) | |
| Purchased power | Purchased power | (301) | | | (108) | | | (2) | | | | — | | | (411) | | Purchased power | (265) | | | (152) | | | (6) | | | | — | | | (423) | |
Other cost of sales(a)(b) | Other cost of sales(a)(b) | (500) | | | (90) | | | (6) | | | | — | | | (596) | | Other cost of sales(a)(b) | (462) | | | (81) | | | 10 | | | | 1 | | | (532) | |
| Mark-to-market for economic hedging activities | Mark-to-market for economic hedging activities | (216) | | | (2) | | | (3) | | | | 1 | | | (220) | | Mark-to-market for economic hedging activities | 49 | | | — | | | — | | | | (1) | | | 48 | |
| Contract and emission credit amortization | Contract and emission credit amortization | (6) | | | — | | | — | | | | — | | | (6) | | Contract and emission credit amortization | (1) | | | — | | | — | | | | — | | | (1) | |
| Gross margin | Gross margin | $ | 614 | | | $ | 290 | | | $ | 63 | | | | $ | (1) | | | $ | 966 | | Gross margin | $ | 576 | | | $ | 233 | | | $ | 111 | | | | $ | (3) | | | $ | 917 | |
| Less: Mark-to-market for economic hedging activities, net | Less: Mark-to-market for economic hedging activities, net | (6) | | | 14 | | | 13 | | | | — | | | 21 | | Less: Mark-to-market for economic hedging activities, net | 49 | | | (20) | | | 15 | | | | — | | | 44 | |
| Less: Contract and emission credit amortization, net | Less: Contract and emission credit amortization, net | (6) | | | — | | | — | | | | — | | | (6) | | Less: Contract and emission credit amortization, net | (1) | | | — | | | — | | | | — | | | (1) | |
| Economic gross margin | Economic gross margin | $ | 626 | | | $ | 276 | | | $ | 50 | | | | $ | (1) | | | $ | 951 | | Economic gross margin | $ | 528 | | | $ | 253 | | | $ | 96 | | | | $ | (3) | | | $ | 874 | |
| (a) Includes capacity and emissions credits | (a) Includes capacity and emissions credits | | (a) Includes capacity and emissions credits |
| (b) Includes $443 million and $2 million of TDSP expense in Texas and East, respectively | | | | | |
| (b) Includes $429 million and $2 million of TDSP expense in Texas and East, respectively | | (b) Includes $429 million and $2 million of TDSP expense in Texas and East, respectively | | | |
| Business Metrics | Business Metrics | | | | Business Metrics | | | |
| Mass Market electricity sales volume (GWh) | 9,129 | | | 1,913 | | | — | | | | 11,042 | | |
| C&I electricity sales volume (GWh) | 4,720 | | | 288 | | | — | | | | 5,008 | | |
| Natural gas sales volume (MDth) | — | | 3,054 | | — | | | | 3,054 | |
| Average retail Mass Market customer count (in thousands) | 2,269 | | 1,029 | | — | | | | 3,298 | |
| Ending retail Mass Market customer count (in thousands) | 2,239 | | 1,038 | | — | | | | 3,277 | |
| Home electricity sales volume (GWh) | | Home electricity sales volume (GWh) | 7,748 | | | 2,548 | | | — | | | | 10,296 | |
| Business electricity sales volume (GWh) | | Business electricity sales volume (GWh) | 4,456 | | | 389 | | | — | | | | 4,845 | |
| Home natural gas sales volume (MDth) | | Home natural gas sales volume (MDth) | — | | 10,509 | | — | | | | 10,509 |
Average retail Home customer count (in thousands)(a) | | Average retail Home customer count (in thousands)(a) | 2,442 | | 1,220 | | — | | | | 3,662 |
Ending retail Home customer count (in thousands)(a) | | Ending retail Home customer count (in thousands)(a) | 2,439 | | 1,212 | | — | | | | 3,651 |
| GWh sold | GWh sold | 11,401 | | 1,849 | | 1,562 | | | | 14,812 | GWh sold | 6,036 | | 2,535 | | 2,559 | | | | 11,130 |
GWh generated:(a) | | | | |
GWh generated(b) | | GWh generated(b) | | | |
| Coal | Coal | 6,403 | | | 479 | | — | | | | 6,882 | | Coal | 3,060 | | | 335 | | — | | | | 3,395 | |
| Gas | Gas | 1,720 | | | 472 | | 1,568 | | | | 3,760 | | Gas | 674 | | | 149 | | 2,355 | | | | 3,178 | |
| Nuclear | Nuclear | 2,522 | | | — | | — | | | | 2,522 | | Nuclear | 2,302 | | | — | | — | | | | 2,302 | |
| Oil | Oil | — | | 14 | | — | | | | 14 | | Oil | — | | 18 | | — | | | | 18 | |
| Renewables | — | | — | | 2 | | | | 2 | | |
| | Total | Total | 10,645 | | | 965 | | | 1,570 | | | | | 13,180 | | Total | 6,036 | | | 502 | | | 2,355 | | | | | | 8,893 | |
(a) Includes owned and leased generation, and excludes equity investments | | | | |
| (a) Home customer count includes recurring residential and small commercial customers, including municipal aggregations | | (a) Home customer count includes recurring residential and small commercial customers, including municipal aggregations | | | |
| (b) Includes owned and leased generation, and excludes equity investments | | (b) Includes owned and leased generation, and excludes equity investments | | | |
The table below represents the weather metrics for the three months ended June 30, 2020March 31, 2021 and 2019:2020:
| | | | Three months ended June 30, | | | Three months ended March 31, | |
| Weather Metrics | Weather Metrics | Texas | | East | | West/Other (b) | | Weather Metrics | Texas | | East | | West/Services/Other (b) | |
| 2020 | | | | | | | |
| 2021 | | 2021 | | | | | | |
CDDs (a) | CDDs (a) | 1,012 | | | 353 | | | 562 | | | CDDs (a) | 86 | | | 38 | | | 37 | | |
HDDs (a) | HDDs (a) | 70 | | | 634 | | | 178 | | | HDDs (a) | 1,120 | | | 2,350 | | | 1,201 | | |
| 2019 | | | |
| 2020 | | 2020 | | |
| CDDs | CDDs | 934 | | | 348 | | | 513 | | | CDDs | 170 | | | 56 | | | 76 | | |
| HDDs | HDDs | 70 | | | 465 | | | 192 | | | HDDs | 791 | | | 2,045 | | | 994 | | |
| 10-year average | 10-year average | | | 10-year average | | |
| CDDs | CDDs | 1,002 | | | 361 | | | 552 | | | CDDs | 116 | | | 38 | | | 51 | | |
| HDDs | HDDs | 60 | | | 501 | | | 206 | | | 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 $180$743 million and economic gross margin increased $109$66 million both of which include intercompany sales, during the three months ended June 30, 2020,March 31, 2021, compared to the same period in 2019.2020.
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 resulting from lower natural gas prices | $ | 10034 | |
Higher gross margin from higher retailLower net revenue of $91 million, due to increasedlower volumes from the acquisitionimpact of Stream in August 2019, higherweather of $14 million, and lower net revenue rates of $23 million, or $2.50 per MWh, driven by customer term, product, and mix and increased load of 256,000 MWhs from favorable weather of $21 million, partially offset by a decrease of $87 million due to attrition and customer mix | 48 $0.75 per MWh, or $9 million. | |
Lower gross margin due to a decrease in net sales of generation to third parties, as the supply was fully utilized to serve the Company's retail load in 2020 | (67)(23) | |
| Lower gross margin from market optimization activities | (8)(9) | |
| |
| Other | (1)4 | |
IncreaseDecrease in economic gross margin | $ | 72 (431) | |
| Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | 47475 | |
Increase in contract and emission credit amortization | 5 | |
| Increase in gross margin | $ | 12444 | |
East
| | | | | | | | |
| | (In millions) |
Higher gross margin due to higher revenues of approximately $10 million, or $4.50 per MWh, and lower supply costsWinter Storm Uri, primarily driven by lower electricity and natural gas prices of approximately $8 million, or $3.50 per MWhoptimization during volatile pricing that occurred during the weather event | | $ | 18154 | |
Higher gross margin driven by a 42% increase in New York realized capacity pricesThe following explanations exclude the impact of Winter Storm Uri: | | 12 | |
Higher gross margin due to increased volumes from the acquisition of StreamDirect Energy in August 2019January 2021, including $202 million from natural gas and $72 million from electricity | | 11274 | |
Higher gross margin fromdue to a lower of cost or market optimization activitiesadjustment on oil inventory in 2020 | | 429 | |
Lower gross margin due to a 25% decrease in New England capacity pricesrealized power pricing, partially offset by an increase in economic generation volumes primarily at Midwest Generation | | (10)(8) | |
| | |
| | |
| | |
| Other | | 16 | |
| Increase in economic gross margin | | $ | 36455 | |
| Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | | 31182 | |
| | |
| Increase in gross margin | | $ | 67637 | |
West/Services/Other
| | | | | |
| (In millions) |
Higher gross margin due to Winter Storm Uri, primarily driven by increased California resource adequacynatural gas optimization during volatile pricing that occurred during the weather event | $ | 1013 | |
| The following explanations exclude the impact of Winter Storm Uri: | |
Higher gross margin due to spark spread expansion at Cottonwoodincreased volumes from the acquisition of Direct Energy in January 2021 | 685 | |
Lower gross margin due to the Canal 3 substantial completion payment earnedgeneration outage insurance proceeds received in 20192020 | (8)(30) | |
Lower gross margin from marketdue 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 | (7)(8) | |
| |
| Other | (1)(3) | |
| |
EconomicIncrease in economic gross margin | $ | —41 | |
DecreaseIncrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | (12)20 | |
| |
DecreaseIncrease in gross margin | $ | (12)61 | |
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 $66$677 million during the three months ended June 30, 2020,March 31, 2021, compared to the same period in 2019.2020.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by segment was as follows:
| | | Three months ended June 30, 2020 | | | Three months ended March 31, 2021 |
| (In millions) | (In millions) | Texas | | East | | West/Other | | | Eliminations | | Total | (In millions) | Texas | | East | | West/Services/Other | | | Eliminations | | Total |
| Mark-to-market results in operating revenues | Mark-to-market results in operating revenues | | | | | | | | | | | Mark-to-market results in operating revenues | | | | | | | | | | |
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | $ | (1) | | | $ | 18 | | | $ | — | | | | $ | 1 | | | $ | 18 | | |
| | Net unrealized gains on open positions related to economic hedges | 1 | | | 22 | | | 1 | | | | 1 | | | 25 | | |
| Total mark-to-market gains in operating revenues | $ | — | | | $ | 40 | | | $ | 1 | | | | $ | 2 | | | $ | 43 | | |
| Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges | | 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 | | Reversal of acquired (gain) positions related to economic hedges | — | | | (3) | | | — | | | | — | | | (3) | |
| Net unrealized (losses)/gains on open positions related to economic hedges | | Net unrealized (losses)/gains on open positions related to economic hedges | (1) | | | 14 | | | (24) | | | | 1 | | | (10) | |
| Total mark-to-market (losses) in operating revenues | | Total mark-to-market (losses) in operating revenues | $ | (1) | | | $ | (4) | | | $ | (28) | | | | $ | 1 | | | $ | (32) | |
| Mark-to-market results in operating costs and expenses | Mark-to-market results in operating costs and expenses | | | | | | | | | | | Mark-to-market results in operating costs and expenses | | | | | | | | | | |
| Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges | $ | 14 | | | $ | — | | | $ | (1) | | | | $ | (1) | | | $ | 12 | | |
| Reversal of previously recognized unrealized losses on settled positions related to economic hedges | | 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 | Reversal of acquired loss positions related to economic hedges | 2 | | | 1 | | | — | | | | — | | | 3 | | Reversal of acquired loss positions related to economic hedges | 36 | | | 112 | | | — | | | | — | | | 148 | |
| Net unrealized gains on open positions related to economic hedges | Net unrealized gains on open positions related to economic hedges | 25 | | | 4 | | | 1 | | | | (1) | | | 29 | | 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 | Total mark-to-market gains in operating costs and expenses | $ | 41 | | | $ | 5 | | | $ | — | | | | $ | (2) | | | $ | 44 | | Total mark-to-market gains in operating costs and expenses | $ | 525 | | | $ | 166 | | | $ | 63 | | | | $ | (1) | | | $ | 753 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three months ended June 30, 2019 | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Other | | | | Eliminations | | Total |
| Mark-to-market results in operating revenues | | | | | | | | | | | |
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | $ | (13) | | | $ | 12 | | | $ | 1 | | | | | $ | — | | | $ | — | |
| | | | | | | | | | | |
| Net unrealized gains on open positions related to economic hedges | 223 | | | 4 | | | 15 | | | | | (1) | | | 241 | |
| Total mark-to-market gains in operating revenues | $ | 210 | | | $ | 16 | | | $ | 16 | | | | | $ | (1) | | | $ | 241 | |
| Mark-to-market results in operating costs and expenses | | | | | | | | | | | |
| Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges | $ | 12 | | | $ | (1) | | | $ | — | | | | | $ | — | | | $ | 11 | |
| Reversal of acquired loss positions related to economic hedges | — | | | 1 | | | — | | | | | — | | | 1 | |
| Net unrealized (losses) on open positions related to economic hedges | (228) | | | (2) | | | (3) | | | | | 1 | | | (232) | |
| Total mark-to-market (losses) in operating costs and expenses | $ | (216) | | | $ | (2) | | | $ | (3) | | | | | $ | 1 | | | $ | (220) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 June 30, 2020,March 31, 2021, the $43$32 million gainloss in operating revenues from economic hedge positions was driven primarily by an increasethe 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 decreasesincreases in New York capacity prices, as well as the reversal of previously recognized unrealized losses on contracts that settled during the period.West power prices. The $44$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 June 30, 2019,March 31, 2020, the $241$4 million gainloss 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 decreasesgains on power positions due to declines in natural gas prices, ERCOT heat rate contraction, and decreases in ERCOTWest/Services/Other power prices. The $220$48 million lossgain in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of decreases in natural gas prices, ERCOT heat rate contraction, and decreases in ERCOT power prices, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period.period, as well as gains on ERCOT heat rate positions due to heat rate expansion.
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 June 30, 2020March 31, 2021 and 2019.2020. 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 June 30, | | | Three months ended March 31, |
| (In millions) | (In millions) | 2020 | | 2019 | (In millions) | 2021 | | 2020 |
| Trading gains/(losses) | | | | |
| Trading gains | | Trading gains | | | |
| Realized | Realized | $ | 16 | | | $ | 15 | | Realized | $ | 59 | | | $ | 7 | |
| Unrealized | Unrealized | (1) | | | 12 | | Unrealized | 4 | | | 11 | |
| Total trading gains | Total trading gains | $ | 15 | | | $ | 27 | | Total trading gains | $ | 63 | | | $ | 18 | |
Operations and Maintenance Expense
Operations and maintenance expense are comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Other | | Corporate | | Eliminations | | Total |
| | | | | | | | | | | |
| Three months ended June 30, 2020 | $ | 158 | | | $ | 94 | | | $ | 26 | | | $ | 2 | | | $ | (1) | | | $ | 279 | |
| Three months ended June 30, 2019 | 152 | | | 101 | | | 32 | | | 1 | | | (2) | | | 284 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (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 decreasedincreased by $5$59 million for the three months ended June 30, 2020,March 31, 2021, compared to the same period in 2019,2020, 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.
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) |
Decrease in deactivation costs primarily due to work done at Midwest Generation in 2019 | $ | (10) | |
Decrease due to return to service costs at Gregory in June 2019 | (7) | |
Decrease in variable chemical costs due to a reduction in East generation volumes | (4) | |
Increase in outages primarily due to planned outages at Midwest Generation in 2020 of $4 million, as well as incremental expenses of $4 million related to COVID-19 | 8 | |
Increase due to the acquisition of StreamDirect Energy in August 2019January 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 | |
| |
| |
Other | 5 | |
DecreaseIncrease in operationsselling, general and maintenance expenseadministrative costs | $ | (5)140 | |
Other Cost of OperationsProvision for Credit Losses
Other cost of operationsProvision for credit losses are comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Other | | Total |
| | | | | | | |
| Three months ended June 30, 2020 | $ | 38 | | | $ | 21 | | | $ | 4 | | | $ | 63 | |
| Three months ended June 30, 2019 | 37 | | | 20 | | | 5 | | | 62 | |
Other costs of operations increased $1 million for the three months ended June 30, 2020, compared to the same period in 2019, due to an increase in gross revenue tax due to the acquisition of Stream Energy in August 2019. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (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 | |
Depreciation and Amortization
Depreciation and amortization are comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Other | | Corporate | | Total |
| Three months ended June 30, 2020 | $ | 59 | | | $ | 33 | | | $ | 8 | | | $ | 10 | | | $ | 110 | |
| Three months ended June 30, 2019 | 40 | | | 30 | | | 7 | | | 8 | | | 85 | |
Depreciation and amortization increased by $25 million, primarily due to the acquisition of Stream Energy in August 2019.
Selling, General and Administrative Costs
Selling, general and administrative costs are comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Other | | Corporate | | Total |
| Three months ended June 30, 2020 | $ | 131 | | | $ | 62 | | | $ | 7 | | | $ | 8 | | | $ | 208 | |
| Three months ended June 30, 2019 | 121 | | | 75 | | | 10 | | | 5 | | | 211 | |
| | | | | | | | | |
Selling, general and administrative costs decreased by $3 million for the three months ended June 30, 2020, compared to the same period in 2019, due to the following:
| | | | | |
| (In millions) |
Decrease in corporate and legal litigation accrualsIncrease 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 | $ | (10)585 | |
Decrease in bad debt expense primarily due to a one-time provision in 2019, partially offset by increase due to the acquisition of Stream Energy and the impact of COVID-19 | (4) | |
Increase due to the acquisition of StreamDirect Energy in August 2019January 2021, partially offset by improved collections | 9 2 |
| |
Increase in amortization of commissionsprovision for credit losses | 4 | |
Other | (2) | |
Decrease in selling, general and administrative costs | $ | (3)587 | |
Reorganization
Acquisition-Related Transaction and Integration Costs
ReorganizationAcquisition-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 employee severance and contract cancellation costs, decreased by $2consulting services.
Gain on sale of assets
A gain on the sale of assets of $17 million was recorded for the three months ended June 30, 2020, comparedMarch 31, 2021 due to the same periodsale of Agua Caliente in 2019, driven by significant achievement of the operationsFebruary 2021 and cost excellence portion of the Transformation Plan during 2019.
Other Income, Net
Other income, net decreased by $6 million for the three months ended June 30,March 31, 2020 comparedrelated to the same period in 2019, primarily due to decreases in interest incomesale of land and dividends received from cost method investments in 2020, partially offset by an increase in pension and postretirement income.January 2020.
LossImpairment losses on Debt Extinguishmentinvestments
A lossImpairment losses on debt extinguishmentinvestments of $47$18 million waswere recorded during the three months ended June 30, 2019, driven byMarch 31, 2020 related to the redemptionimpairment of the 2024 Senior Notes and the repayment of the 2023 Term Loan Facility.Petra Nova Parish Holdings, as further discussed in Note 8, Impairments.
Interest ExpenseGross Margin
Interest expense decreasedThe 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 $9 millionthe Company's chief operating decision maker. Economic gross margin is defined as the sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales. Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emission credit amortization, or other operating costs.
The below tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended June 30, 2020,March 31, 2021 and 2020:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three months ended March 31, 2021 |
| ($ 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 $38 million of TDSP expense in Texas and East, respectively | | | | | | | | | |
| Business Metrics | | | | | | | | | | | | |
| Home electricity sales volume (GWh) | 10,186 | | | 4,076 | | | 320 | | | | | | | | 14,582 | |
| Business electricity sales volume (GWh) | 6,524 | | | 13,838 | | | 630 | | | | | | | | 20,992 | |
| Home natural gas sales volume (MDth) | — | | | 42,434 | | | 35,696 | | | | | | | | 78,130 | |
| Business natural gas sales volume (MDth) | — | | | 264,588 | | | — | | | | | | | | 264,588 | |
Average retail Home customer count (in thousands) (a) | 3,082 | | | 1,947 | | | 552 | | | | | | | | 5,581 | |
Ending retail Home customer count (in thousands) (a) | 3,086 | | | 2,042 | | | 553 | | | | | | | | 5,681 | |
| GWh sold | 7,349 | | | 3,245 | | | 2,029 | | | | | | | | 12,623 | |
GWh generated:(b) | | | | | | | | | | | | |
| Coal | 3,840 | | | 1,301 | | | — | | | | | | | | 5,141 | |
| Gas | 1,185 | | | 107 | | | 1,985 | | | | | | | | 3,277 | |
| Nuclear | 2,324 | | | — | | | — | | | | | | | | 2,324 | |
| Oil | — | | | 17 | | | — | | | | | | | | 17 | |
| | | | | | | | | | | | |
| Total | 7,349 | | | 1,425 | | | 1,985 | | | | | | | | 10,759 | |
| (a) Home customer count includes recurring residential and small commercial customers, including municipal aggregations | | | | | | | |
| (b) Includes owned and leased generation, and excludes equity investments | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three months ended March 31, 2020 |
| ($ 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 | | | | | | | | | | | |
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 2019, primarily due to2020.
The tables below describe the debt reduction of $600 millionchanges in gross margin and refinancing of $1.8 billion at lower interest rates in 2019.economic gross margin by segment:
Income Tax Expense/(Benefit)
For the three months ended June 30, 2020, income tax expense of $101 million was recorded on pre-tax income of $414 million. For the same period in 2019, an income tax benefit of $1 million was recorded on pre-tax income of $188 million. The effective tax rates were 24.4% and (0.5)% for the three months ended June 30, 2020 and 2019, respectively.
For the three months ended June 30, 2020, the effective tax rate was higher than the statutory rate of 21%, due to state tax expense partially offset by an excess tax benefit related to share-based compensation. For the same period in 2019, the effective tax rates was lower than the statutory rate of 21%, primarily due to the tax benefit for the change in valuation allowance, partially offset by state tax expense.
Income from Discontinued Operations, Net of Income TaxTexas
| | | | | |
| (In millions) | Three months ended June 30, 2019 |
South Central PortfolioLower gross margin due to Winter Storm Uri, primarily driven by an increase in unhedgeable ancillary and operating reserve demand curve supply costs | $ | 1 (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 | |
East
| | | | | | | | |
| | (In millions) |
CarlsbadHigher gross margin due to Winter Storm Uri, primarily driven by natural gas optimization during volatile pricing that occurred during the weather event | | $ | 10154 | |
| 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) |
GenOn | 2 | |
Income from discontinued operations, net of taxHigher 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 | |
For the three months ended June 30, 2019, NRG recorded income from discontinued operations, net of income tax of $13 million, as further described in Note 4, Acquisitions, Discontinued Operations and Dispositions.
Management’s discussion ofMark-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 $677 million during the results of operations for the sixthree months ended June 30, 2020 and 2019
Electricity Prices
The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the six months ended June 30, 2020 and 2019. The average on-peak power prices decreased due to mild winter weather and lower demand due to COVID-19.
| | | | | | | | | | | | | | | | | |
| | Average on Peak Power Price ($/MWh) | | | | |
| Six months ended June 30, | | | | |
| Region | 2020 | | 2019 | | Change % |
| Texas | | | | | |
ERCOT - Houston (a) | $ | 24.84 | | | $ | 30.04 | | | (17) | % |
ERCOT - North(a) | 22.23 | | | 29.08 | | | (24) | % |
| | | | | |
| East | | | | | |
NY J/NYC(b) | 21.42 | | | 37.34 | | | (43) | % |
NEPOOL(b) | 22.43 | | | 37.28 | | | (40) | % |
COMED (PJM)(b) | 20.29 | | | 28.44 | | | (29) | % |
PJM West Hub(b) | 21.63 | | | 31.17 | | | (31) | % |
| | | | | |
| West | | | | | |
MISO - Louisiana Hub(b) | 22.10 | | | 33.12 | | | (33) | % |
CAISO - SP15(b) | 23.93 | | | 36.86 | | | (35) | % |
(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 six months ended June 30, 2020 and 2019:
| | | | | | | | | | | | | | | | | |
| | Average Realized Power Price ($/MWh) | | | | |
| Six months ended June 30, | | | | |
| Region | 2020 | | 2019 | | Change % |
East(a) | $ | 36.63 | | | $ | 36.57 | | | — | % |
West/Other | 28.45 | | | 31.41 | | | (9) | % |
(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 $19.64/MWh in the six months ended June 30, 2020 and $6.84/MWh in the six months ended June 30, 2019
The average realized power prices were flat in the East region for the six months ended June 30, 2020 asMarch 31, 2021, compared to the same period in 20192020.
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.
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 Company's hedged positions. The average realized power prices decreasedDirect Energy acquisition in January 2021.
Other Cost of Operations
Other cost of operations are comprised of the West/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 regioncosts of operations increased $19 million for the three months ended March 31, 2021, compared to the same period in 2020, primarily due to lower powerthe Direct Energy acquisition in January 2021.
Depreciation and gas prices.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.
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 $18 million were recorded during the three months ended March 31, 2020 related to the impairment of Petra Nova Parish Holdings, as further discussed in Note 8, Impairments.
Gross Margin
The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of sales, which includes cost of fuel, other costs of sales, contract and emission credit amortization and mark-to-market for economic hedging activities.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales. Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emission credit amortization, or other operating costs.
The below tables present the composition and reconciliation of gross margin and economic gross margin for the sixthree months ended June 30, 2020March 31, 2021 and 2019:2020:
| | | Six months ended June 30, 2020 | | | Three months ended March 31, 2021 |
| ($ In millions) | ($ In millions) | Texas | | East | | West/Other | | | Corporate/Eliminations | | Total | ($ In millions) | Texas | | East | | West/Services/Other | | | Corporate/Eliminations | | Total |
| Retail revenue | Retail revenue | $ | 2,813 | | | $ | 681 | | | $ | — | | | | $ | (1) | | | $ | 3,493 | | Retail revenue | $ | 2,114 | | | $ | 3,543 | | | $ | 505 | | | | $ | — | | | $ | 6,162 | |
| Energy revenue | Energy revenue | 10 | | | 64 | | | 135 | | | | (2) | | | 207 | | Energy revenue | 285 | | | 126 | | | 70 | | | | 1 | | | 482 | |
| Capacity revenue | Capacity revenue | — | | | 313 | | | 31 | | | | — | | | 344 | | Capacity revenue | — | | | 141 | | | 14 | | | | — | | | 155 | |
| Mark-to-market for economic hedging activities | Mark-to-market for economic hedging activities | — | | | 20 | | | 16 | | | | 3 | | | 39 | | Mark-to-market for economic hedging activities | (1) | | | (4) | | | (28) | | | | 1 | | | (32) | |
| Other revenue | Other revenue | 113 | | | 27 | | | 37 | | | | (3) | | | 174 | | Other revenue | 1,304 | | | 19 | | | 4 | | | | (3) | | | 1,324 | |
| Operating revenue | Operating revenue | 2,936 | | | 1,105 | | | 219 | | | | (3) | | | 4,257 | | Operating revenue | 3,702 | | | 3,825 | | | 565 | | | | (1) | | | 8,091 | |
| Cost of fuel | Cost of fuel | (226) | | | (74) | | | (66) | | | | — | | | (366) | | Cost of fuel | (724) | | | (18) | | | (25) | | | | — | | | (767) | |
| Purchased power | Purchased power | (468) | | | (249) | | | (9) | | | | 3 | | | (723) | | Purchased power | (986) | | | (2,509) | | | (172) | | | | — | | | (3,667) | |
Other cost of sales (a) (b) | (1,016) | | | (189) | | | 10 | | | | — | | | (1,195) | | |
Other cost of sales(b)(c) | | Other cost of sales(b)(c) | (1,896) | | | (594) | | | (259) | | | | — | | | (2,749) | |
| Mark-to-market for economic hedging activities | Mark-to-market for economic hedging activities | 90 | | | 5 | | | — | | | | (3) | | | 92 | | Mark-to-market for economic hedging activities | 525 | | | 166 | | | 63 | | | | (1) | | | 753 | |
| Contract and emission credit amortization | Contract and emission credit amortization | (2) | | | — | | | — | | | | — | | | (2) | | Contract and emission credit amortization | (1) | | | — | | | — | | | | — | | | (1) | |
| Gross margin | Gross margin | $ | 1,314 | | | $ | 598 | | | $ | 154 | | | | $ | (3) | | | $ | 2,063 | | Gross margin | $ | 620 | | | $ | 870 | | | $ | 172 | | | | $ | (2) | | | $ | 1,660 | |
| Less: Mark-to-market for economic hedging activities, net | Less: Mark-to-market for economic hedging activities, net | 90 | | | 25 | | | 16 | | | | — | | | 131 | | Less: Mark-to-market for economic hedging activities, net | 524 | | | 162 | | | 35 | | | | — | | | 721 | |
| Less: Contract and emission credit amortization, net | Less: Contract and emission credit amortization, net | (2) | | | — | | | — | | | | — | | | (2) | | Less: Contract and emission credit amortization, net | (1) | | | — | | | — | | | | — | | | (1) | |
| Economic gross margin | Economic gross margin | $ | 1,226 | | | $ | 573 | | | $ | 138 | | | | $ | (3) | | | $ | 1,934 | | Economic gross margin | $ | 97 | | | $ | 708 | | | $ | 137 | | | | $ | (2) | | | $ | 940 | |
(a)Includes capacity and emission credits | | | | | | | | | | | |
(b)Includes $914 million and $5 million of TDSP expense in Texas and East, respectively | | |
| (a) Includes trading gains and losses and ancillary revenues | | (a) Includes trading gains and losses and ancillary revenues | | | |
| (b) Includes capacity and emissions credits | | (b) Includes capacity and emissions credits |
| (c) Includes $590 million and $38 million of TDSP expense in Texas and East, respectively | | (c) Includes $590 million and $38 million of TDSP expense in Texas and East, respectively | | | |
| Business Metrics | Business Metrics | | | | Business Metrics | | | |
| Mass Market electricity sales volume (GWh) | 17,511 | | | 4,903 | | | — | | | | | 22,414 | |
| C&I electricity sales volume (GWh) | 8,669 | | | 754 | | | — | | | | | 9,423 | |
| Natural gas sales volume (MDth) | — | | | 14,100 | | | — | | | | | 14,100 | |
| Average retail Mass Market customer count (in thousands) | 2,443 | | | 1,205 | | | — | | | | | 3,648 | |
| Ending retail Mass Market customer count (in thousands) | 2,447 | | | 1,171 | | | — | | | | | 3,618 | |
| Home electricity sales volume (GWh) | | Home electricity sales volume (GWh) | 10,186 | | | 4,076 | | | 320 | | | | | 14,582 | |
| Business electricity sales volume (GWh) | | Business electricity sales volume (GWh) | 6,524 | | | 13,838 | | | 630 | | | | | 20,992 | |
| Home natural gas sales volume (MDth) | | Home natural gas sales volume (MDth) | — | | | 42,434 | | | 35,696 | | | | | 78,130 | |
| Business natural gas sales volume (MDth) | | Business natural gas sales volume (MDth) | — | | | 264,588 | | | — | | | | | 264,588 | |
Average retail Home customer count (in thousands) (a) | | Average retail Home customer count (in thousands) (a) | 3,082 | | | 1,947 | | | 552 | | | | | 5,581 | |
Ending retail Home customer count (in thousands) (a) | | Ending retail Home customer count (in thousands) (a) | 3,086 | | | 2,042 | | | 553 | | | | | 5,681 | |
| GWh sold | GWh sold | 13,574 | | | 3,767 | | | 4,745 | | | | | 22,086 | GWh sold | 7,349 | | | 3,245 | | | 2,029 | | | | | 12,623 | |
GWh generated (a) | | | | | | | | |
GWh generated:(b) | | GWh generated:(b) | | | |
| Coal | Coal | 6,837 | | | 394 | | | — | | | | | 7,231 | Coal | 3,840 | | | 1,301 | | | — | | | | | 5,141 | |
| Gas | Gas | 2,015 | | | 628 | | | 4,601 | | | | | 7,244 | Gas | 1,185 | | | 107 | | | 1,985 | | | | | 3,277 | |
| Nuclear | Nuclear | 4,562 | | | — | | | — | | | | | 4,562 | Nuclear | 2,324 | | | — | | | — | | | | | 2,324 | |
| Oil | Oil | — | | | 84 | | | — | | | | | 84 | Oil | — | | | 17 | | | — | | | | | 17 | |
| | Total | Total | 13,414 | | | 1,106 | | | 4,601 | | | | | 19,121 | Total | 7,349 | | | 1,425 | | | 1,985 | | | | | 10,759 | |
(a) Includes owned and leased generation, and excludes equity investments | | |
| | (a) Home customer count includes recurring residential and small commercial customers, including municipal aggregations | | (a) Home customer count includes recurring residential and small commercial customers, including municipal aggregations | | | |
| (b) Includes owned and leased generation, and excludes equity investments | | (b) Includes owned and leased generation, and excludes equity investments | | | |
| | | Six months ended June 30, 2019 | | | Three months ended March 31, 2020 |
| ($ In millions) | ($ In millions) | Texas | | East | | West/Other | | | Corporate/Eliminations | | Total | ($ In millions) | Texas | | East | | West/Services/Other | | | Corporate/Eliminations | | Total |
| Retail revenue | Retail revenue | $ | 2,686 | | | $ | 591 | | | $ | — | | | | $ | (3) | | | $ | 3,274 | | Retail revenue | $ | 1,292 | | | $ | 352 | | | $ | 18 | | | | $ | (1) | | | $ | 1,661 | |
| Energy revenue | Energy revenue | 241 | | | 174 | | | 110 | | | | 1 | | | 526 | | Energy revenue | 5 | | | 45 | | | 75 | | | | (1) | | | 124 | |
| Capacity revenue | Capacity revenue | — | | | 339 | | | 18 | | | | — | | | 357 | | Capacity revenue | — | | | 134 | | | 15 | | | | — | | | 149 | |
| Mark-to-market for economic hedging activities | Mark-to-market for economic hedging activities | 241 | | | 1 | | | 20 | | | | (1) | | | 261 | | Mark-to-market for economic hedging activities | — | | | (20) | | | 15 | | | | 1 | | | (4) | |
| | Other revenue | Other revenue | 135 | | | 28 | | | 51 | | | | (2) | | | 212 | | Other revenue | 61 | | | 10 | | | 20 | | | | (2) | | | 89 | |
| Operating revenue | Operating revenue | 3,303 | | | 1,133 | | | 199 | | | | (5) | | | 4,630 | | Operating revenue | 1,358 | | | 521 | | | 143 | | | | (3) | | | 2,019 | |
| Cost of fuel | Cost of fuel | (349) | | | (100) | | | (68) | | | | — | | | (517) | | Cost of fuel | (103) | | | (55) | | | (36) | | | | — | | | (194) | |
| Purchased Power | (628) | | | (299) | | | (2) | | | | — | | | (929) | | |
Other cost of sales (a) (b) | (986) | | | (165) | | | (17) | | | | — | | | (1,168) | | |
| Purchased power | | Purchased power | (265) | | | (152) | | | (6) | | | | — | | | (423) | |
Other cost of sales(a)(b) | | Other cost of sales(a)(b) | (462) | | | (81) | | | 10 | | | | 1 | | | (532) | |
| Mark-to-market for economic hedging activities | Mark-to-market for economic hedging activities | (221) | | | 1 | | | (1) | | | | 1 | | | (220) | | Mark-to-market for economic hedging activities | 49 | | | — | | | — | | | | (1) | | | 48 | |
| Contract and emission credit amortization | Contract and emission credit amortization | (11) | | | — | | | — | | | | — | | | (11) | | Contract and emission credit amortization | (1) | | | — | | | — | | | | — | | | (1) | |
| Gross margin | Gross margin | $ | 1,108 | | | $ | 570 | | | $ | 111 | | | | $ | (4) | | | $ | 1,785 | | Gross margin | $ | 576 | | | $ | 233 | | | $ | 111 | | | | $ | (3) | | | $ | 917 | |
| Less: Mark-to-market for economic hedging activities, net | Less: Mark-to-market for economic hedging activities, net | 20 | | | 2 | | | 19 | | | | — | | | 41 | | Less: Mark-to-market for economic hedging activities, net | 49 | | | (20) | | | 15 | | | | — | | | 44 | |
| Less: Contract and emission credit amortization, net | Less: Contract and emission credit amortization, net | (11) | | | — | | | — | | | | — | | | (11) | | Less: Contract and emission credit amortization, net | (1) | | | — | | | — | | | | — | | | (1) | |
| Economic gross margin | Economic gross margin | $ | 1,099 | | | $ | 568 | | | $ | 92 | | | | $ | (4) | | | $ | 1,755 | | Economic gross margin | $ | 528 | | | $ | 253 | | | $ | 96 | | | | $ | (3) | | | $ | 874 | |
(a) Includes capacity and emissions credits | (a) Includes capacity and emissions credits | | | | | | | | | | | (a) Includes capacity and emissions credits |
(b) Includes $865 million and $5 million of TDSP expense in Texas and East, respectively | | |
| (b) Includes $429 million and $2 million of TDSP expense in Texas and East, respectively | | (b) Includes $429 million and $2 million of TDSP expense in Texas and East, respectively | | | |
| Business Metrics | Business Metrics | | | | Business Metrics | | | |
| Mass Market electricity sales voldume (GWh) | 17,119 | | | 4,407 | | | — | | | | | 21,526 | | |
| C&I electricity sales volume (GWh) | 9,269 | | | 570 | | | — | | | | | 9,839 | | |
| Natural gas sales volume (MDth) | — | | | 13,601 | | | — | | | | | 13,601 | | |
| Average retail Mass Market customer count (in thousands) | 2,288 | | | 1,029 | | | — | | | | | 3,317 | | |
| Ending retail Mass Market customer count (in thousands) | 2,239 | | | 1,038 | | | — | | | | | 3,277 | | |
| Home electricity sales volume (GWh) | | Home electricity sales volume (GWh) | 7,748 | | | 2,548 | | | — | | | | 10,296 | |
| Business electricity sales volume (GWh) | | Business electricity sales volume (GWh) | 4,456 | | | 389 | | | — | | | | 4,845 | |
| Home natural gas sales volume (MDth) | | Home natural gas sales volume (MDth) | — | | 10,509 | | — | | | | 10,509 |
Average retail Home customer count (in thousands)(a) | | Average retail Home customer count (in thousands)(a) | 2,442 | | 1,220 | | — | | | | 3,662 |
Ending retail Home customer count (in thousands)(a) | | Ending retail Home customer count (in thousands)(a) | 2,439 | | 1,212 | | — | | | | 3,651 |
| GWh sold | GWh sold | 20,329 | | | 5,852 | | | 3,502 | | | | | 29,683 | GWh sold | 6,036 | | 2,535 | | 2,559 | | | | 11,130 |
GWh generated (a)(b) | GWh generated (a)(b) | | | | GWh generated (a)(b) | | | |
| Coal | Coal | 11,010 | | | 2,805 | | | — | | | | | 13,815 | | Coal | 3,060 | | | 335 | | — | | | | 3,395 | |
| Gas | Gas | 2,209 | | | 623 | | | 3,500 | | | | | 6,332 | | Gas | 674 | | | 149 | | 2,355 | | | | 3,178 | |
| Nuclear | Nuclear | 5,060 | | | — | | | — | | | | | 5,060 | | Nuclear | 2,302 | | | — | | — | | | | 2,302 | |
| Oil | Oil | — | | | 19 | | | — | | | | | 19 | | Oil | — | | 18 | | — | | | | 18 | |
| Renewables | — | | | — | | | 10 | | | | | 10 | | |
| | Total | Total | 18,279 | | | 3,447 | | | 3,510 | | | | | 25,236 | | Total | 6,036 | | | 502 | | | 2,355 | | | | | | 8,893 | |
(a) Includes owned and leased generation, and excludes equity investments | | | | | |
| (a) Home customer count includes recurring residential and small commercial customers, including municipal aggregations | | (a) Home customer count includes recurring residential and small commercial customers, including municipal aggregations | | | |
| (b) Includes owned and leased generation, and excludes equity investments | | (b) Includes owned and leased generation, and excludes equity investments | | | |
The table below represents the weather metrics for the sixthree months ended June 30, 2020March 31, 2021 and 2019:2020:
| | | | Six months ended June 30, | | | Three months ended March 31, | |
| Weather Metrics | Weather Metrics | Texas | | East | | West/Other (b) | | Weather Metrics | Texas | | East | | West/Services/Other (b) | |
| 2020 | | | | | | | |
| 2021 | | 2021 | | | | | | |
CDDs (a) | CDDs (a) | 1,182 | | | 409 | | | 638 | | | CDDs (a) | 86 | | | 38 | | | 37 | | |
HDDs (a) | HDDs (a) | 861 | | | 2,679 | | | 1,172 | | | HDDs (a) | 1,120 | | | 2,350 | | | 1,201 | | |
| 2019 | | | |
| 2020 | | 2020 | | |
| CDDs | CDDs | 1,008 | | | 382 | | | 544 | | | CDDs | 170 | | | 56 | | | 76 | | |
| HDDs | HDDs | 1,111 | | | 2,922 | | | 1,384 | | | HDDs | 791 | | | 2,045 | | | 994 | | |
| 10-year average | 10-year average | | | 10-year average | | |
| CDDs | CDDs | 1,106 | | | 396 | | | 598 | | | CDDs | 116 | | | 38 | | | 51 | | |
| HDDs | HDDs | 1,055 | | | 2,959 | | | 1,316 | | | 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-CaliforniaWest - California and West-West - South Central regions
Gross Margin and Economic Gross Margin
Gross margin increased $278$743 million and economic gross margin increased $179$66 million both of which include intercompany sales, during the sixthree months ended June 30, 2020,March 31, 2021, compared to the same period in 2019.2020.
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 | |
East
| | | | | | | | |
| | (In millions) |
Higher gross margin due to Winter Storm Uri, primarily driven by natural gas pricesoptimization during volatile pricing that occurred during the weather event | | $ | 158154 | |
| The following explanations exclude the impact of Winter Storm Uri: | | |
Higher gross margin from increased net revenue rates of $168 million due to increased volumes from the acquisition of StreamDirect Energy in August 2019,January 2021, including $202 million from natural gas and higher net revenue rates of $51$72 million or $2.50 per MWh, driven by customer term, product and mix, partially offset by $140 millionfrom electricity | | 274 | |
Higher gross margin due to attrition and customer mixa lower of cost or market adjustment on oil inventory in 2020 | | 7929 | |
Lower gross margin from net sales of generation to third parties, as the supply was fully utilized to serve the Company's retail load in 2020 | | (86) | |
Lower gross margin from market optimization activities | | (14) | |
Lower gross margin due to the sale of emissionsa decrease in 2019realized power pricing, partially offset by an increase in economic generation volumes primarily at Midwest Generation | | (13)(8) | |
| | |
| | |
| | |
| Other | | 36 | |
| Increase in economic gross margin | | $ | 127455 | |
| Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | | 70182 | |
| | |
Increase in contract and emission credit amortization | | 9 | |
Increase in gross margin | | $ | 206637 | |
EastWest/Services/Other
| | | | | |
| (In millions) |
Higher gross margin due to lower supply costs of $31 millionWinter Storm Uri, primarily driven by lower electricity prices of approximately $6 per MWh and lower natural gas prices, partially offset by lower revenues of approximately $2 million, or $0.25 per MWhoptimization during volatile pricing that occurred during the weather event | $ | 2913 | |
| The following explanations exclude the impact of Winter Storm Uri: | |
Higher gross margin due to increased volumes from the acquisition of StreamDirect Energy in August 2019January 2021 | 2585 | |
Higher gross margin due to lower supply costs coupled with an increase in load contract volumes | 21 | |
Higher gross margin driven by a 43% increase in New York realized capacity prices | 17 | |
Lower gross margin due to a lower of cost or market adjustment on oil inventorygeneration outage insurance proceeds received in 2020 | (29)(30) | |
Lower gross margin primarily due to a 68% decrease in economic generation volumes primarily due to dark spread contractions and planned outages | (20) | |
Lower gross margin due to a 25% decrease in New England capacity priceslower economic dispatch and lower average realized pricing associated with current year outages at Cottonwood | (20)(16) | |
Lower gross margin due to a 7% decrease in PJM capacity prices | (11) | |
Lower gross margin from marketcommercial optimization activities | (6)(8) | |
| Other | (1)(3) | |
| |
| Increase in economic gross margin | $ | 541 | |
| Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges | 2320 | |
| |
| Increase in gross margin | $ | 2861 | |
West/Other
| | | | | |
| (In millions) |
Higher gross margin due to generation outage insurance proceeds received in 2020 for forced outages in 2019 | $ | 30 | |
Higher gross margin driven by increased California resource adequacy pricing and lower capacity purchases due to the 2019 Sunrise outage | 18 | |
Higher gross margin due to spark spread expansion at Cottonwood | 11 | |
Higher gross margin due to an extended forced outage at the Sunrise facility in 2019 | 9 | |
Lower gross margin from market optimization activities | (11) | |
Lower gross margin due to the Canal 3 substantial completion payment earned in 2019 | (8) | |
| |
| |
| |
| |
| |
Other | (3) | |
Increase in economic gross margin | $ | 46 | |
Decrease to mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges | (3) | |
Increase in gross margin | $ | 43 | |
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 $90$677 million during the sixthree months ended June 30, 2020,March 31, 2021, compared to the same period in 2019.2020.
The breakdown of gains and losses included in operating revenues and operating costs and expenses by segment was as follows:
| | | Six months ended June 30, 2020 | | | Three months ended March 31, 2021 |
| (In millions) | (In millions) | Texas | | East | | West/Other | | | Eliminations | | Total | (In millions) | Texas | | East | | West/Services/Other | | | Eliminations | | Total |
| Mark-to-market results in operating revenues | Mark-to-market results in operating revenues | | | | | | | | | | | Mark-to-market results in operating revenues | | | | | | | | | | |
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | $ | (1) | | | $ | 4 | | | $ | (5) | | | | $ | 2 | | | $ | — | | |
| | Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges | | 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 | | Reversal of acquired (gain) positions related to economic hedges | — | | | (3) | | | — | | | | — | | | (3) | |
| Net unrealized (losses)/gains on open positions related to economic hedges | | Net unrealized (losses)/gains on open positions related to economic hedges | (1) | | | 14 | | | (24) | | | | 1 | | | (10) | |
| Total mark-to-market (losses) in operating revenues | | Total mark-to-market (losses) in operating revenues | $ | (1) | | | $ | (4) | | | $ | (28) | | | | $ | 1 | | | $ | (32) | |
| Mark-to-market results in operating costs and expenses | | Mark-to-market results in operating costs and expenses | | | | | | | | | | |
| Reversal of previously recognized unrealized losses on settled positions related to economic hedges | | 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 | | Reversal of acquired loss positions related to economic hedges | 36 | | | 112 | | | — | | | | — | | | 148 | |
| Net unrealized gains on open positions related to economic hedges | Net unrealized gains on open positions related to economic hedges | 1 | | | 16 | | | 21 | | | | 1 | | | 39 | | Net unrealized gains on open positions related to economic hedges | 456 | | | 51 | | | 63 | | | | (1) | | | 569 | |
| Total mark-to-market gains in operating revenues | $ | — | | | $ | 20 | | | $ | 16 | | | | $ | 3 | | | $ | 39 | | |
| Mark-to-market results in operating costs and expenses | | | | | | | | | | | |
| Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges | $ | 36 | | | $ | 6 | | | $ | (1) | | | | $ | (2) | | | $ | 39 | | |
| Reversal of acquired loss positions related to economic hedges | 4 | | | — | | | — | | | | — | | | 4 | | |
| Net unrealized gains/(losses) on open positions related to economic hedges | 50 | | | (1) | | | 1 | | | | (1) | | | 49 | | |
| Total mark-to-market gains in operating costs and expenses | Total mark-to-market gains in operating costs and expenses | $ | 90 | | | $ | 5 | | | $ | — | | | | $ | (3) | | | $ | 92 | | Total mark-to-market gains in operating costs and expenses | $ | 525 | | | $ | 166 | | | $ | 63 | | | | $ | (1) | | | $ | 753 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Six months ended June 30, 2019 | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Other | | | | Eliminations | | Total |
| Mark-to-market results in operating revenues | | | | | | | | | | | |
| Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges | $ | (2) | | | $ | (8) | | | $ | 2 | | | | | $ | — | | | $ | (8) | |
| | | | | | | | | | | |
| Net unrealized gains on open positions related to economic hedges | 243 | | | 9 | | | 18 | | | | | (1) | | | 269 | |
| Total mark-to-market gains in operating revenues | $ | 241 | | | $ | 1 | | | $ | 20 | | | | | $ | (1) | | | $ | 261 | |
| Mark-to-market results in operating costs and expenses | | | | | | | | | | | |
| Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges | $ | 35 | | | $ | 4 | | | $ | (1) | | | | | $ | — | | | $ | 38 | |
| Reversal of acquired (gain) positions related to economic hedges | — | | | (1) | | | — | | | | | — | | | (1) | |
| Net unrealized (losses) on open positions related to economic hedges | (256) | | | (2) | | | — | | | | | 1 | | | (257) | |
| Total mark-to-market (losses)/gains in operating costs and expenses | $ | (221) | | | $ | 1 | | | $ | (1) | | | | | $ | 1 | | | $ | (220) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 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 sixthree months ended June 30, 2020,March 31, 2021, the $39$32 million gainloss in operating revenues from economic hedge positions was driven primarily by an increasethe 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 decreasesincreases in New York capacity, New York power, and West/OtherWest power prices. The $92$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 outer year 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 sixthree months ended June 30, 2019,March 31, 2020, the $261$4 million gainloss in operating revenues from economic hedge positions was driven primarily by an increase in value of open positions as a result of decreases in natural gas prices, ERCOT heat rate contraction, and decreases in ERCOT power prices, partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period.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 $220$48 million lossgain in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of decreases in natural gas prices, ERCOT heat rate contraction, and decreases in ERCOT power prices, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period.period, as well as gains on ERCOT heat rate positions due to heat rate expansion.
In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the sixthree months ended June 30, 2020March 31, 2021 and 2019.2020. 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.
| | | | Six months ended June 30, | | | Three months ended March 31, |
| (In millions) | (In millions) | 2020 | | 2019 | (In millions) | 2021 | | 2020 |
| Trading gains | Trading gains | | | | Trading gains | | | |
| Realized | Realized | $ | 23 | | | $ | 31 | | Realized | $ | 59 | | | $ | 7 | |
| Unrealized | Unrealized | 10 | | | 19 | | Unrealized | 4 | | | 11 | |
| Total trading gains | Total trading gains | $ | 33 | | | $ | 50 | | Total trading gains | $ | 63 | | | $ | 18 | |
Operations and Maintenance Expense
Operations and maintenance expense are comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Other | | Corporate | | Eliminations | | Total |
| Six months ended June 30, 2020 | $ | 333 | | | $ | 182 | | | $ | 56 | | | $ | 4 | | | $ | (3) | | | $ | 572 | |
| Six months ended June 30, 2019 | 303 | | | 167 | | | 60 | | | 4 | | | (3) | | | 531 | |
| | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (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 $41$59 million for the sixthree months ended June 30, 2020,March 31, 2021, compared to the same period in 2019,2020, primarily due to the following:
| | | | | |
| (In millions) |
Increase in outages primarily due to planned outages at STP and Midwest Generation in 2020 of $28 million, as well as incremental expenses of $3 million related to COVID-19 | $ | 31 | |
Increase due to settlement of the asbestos liability for Midwest Generation and the resulting reduction of the accrual in 2019 | 27 | |
Increase due to the Stream Energy acquisition in August 2019 | 12 | |
Decrease in variable chemical costs due to a reduction in East generation volumes partially offset by an increase at Sunrise in 2020 as a result of higher volumes | (13) | |
Decrease in deactivation costs primarily due to work done at Midwest Generation and Encina in 2019 | (12) | |
Decrease due to return to service costs at Gregory in June 2019 | (7) | |
Other | 3 | |
Increase in operations and maintenance expense | $ | 41 | |
Other Cost of Operations
Other Costcost of operations are comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Other | | | | | | Total |
| Six months ended June 30, 2020 | $ | 71 | | | $ | 47 | | | $ | 7 | | | | | | | $ | 125 | |
| Six months ended June 30, 2019 | 70 | | | 41 | | | 9 | | | | | | | 120 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| (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 costcosts of operations increased by $5$19 million for the sixthree months ended June 30, 2020,March 31, 2021, compared to the same period in 2019,2020, 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.
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 in ARO expense at the Joliet plant as a result of regulatory requirements | $ | 5 | |
Increase in gross revenue tax due to the acquisition of StreamDirect Energy in August 2019January 2021 | 2 $ | 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 | (2)3 | |
| |
Increase in other cost of operationsselling, general and administrative costs | $ | 5140 | |
79
Depreciation and Amortization
Depreciation and amortization expensesProvision for credit losses are comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Other | | Corporate | | Total |
| Six months ended June 30, 2020 | $ | 118 | | | $ | 66 | | | $ | 16 | | | $ | 19 | | | $ | 219 | |
| Six months ended June 30, 2019 | 80 | | 56 | | 18 | | 16 | | 170 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (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 | |
Depreciation and amortization increased by $49 million for the six months ended June 30, 2020, compared to the same period in 2019, driven primarily by the acquisition of Stream Energy in August 2019.
Selling, General and Administrative Costs
Selling, general and administrative costs comprised of the following:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Texas | | East | | West/Other | | Corporate | | Total |
| Six months ended June 30, 2020 | $ | 261 | | | $ | 126 | | | $ | 16 | | | $ | 14 | | | $ | 417 | |
| Six months ended June 30, 2019 | 238 | | | 140 | | | 17 | | | 10 | | | 405 | |
| | | | | | | | | |
Selling, general and administrative costs increased by $12 million for the six months ended June 30, 2020, compared to the same period in 2019, due to the following:
| | | | | |
| (In millions) |
Increase due to the acquisitionWinter Storm Uri, including:
Increase of Stream Energy in August 2020$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 | $ | 19585 | |
Increase due to higher amortizationacquisition of commissions | 9 | |
DecreaseDirect Energy in selling and marketing spend due to the impact of COVID-19 | (7) | |
Decrease in legal litigation accruals | (6) | |
Decrease in bad debt expense primarily due to a one-time provision in 2019,January 2021, partially offset by increases due to the acquisition of Stream Energy and the impact of COVID-19 | (4)improved collections | 2 |
| |
Other | 1 | |
Increase in selling, general and administrative costsprovision for credit losses | $ | 12587 | |
Reorganization
Acquisition-Related Transaction and Integration Costs
ReorganizationAcquisition-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 employee severance and contract cancellation costs, decreased by $12 million for the six months ended June 30, 2020, compared to the same period in 2019, driven by significant achievement of the operations and cost excellence portion of the Transformation Plan during 2019.consulting services.
Gain on Salesale of Assetsassets
TheA 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 sixthree months ended June 30,March 31, 2020 is related to the sale of land and investments in January 2020.
Equity in Earnings/ Losses of Unconsolidated Affiliates
Equity in losses of unconsolidated affiliates was $21 million for the six months ended June 30, 2019, primarily driven by losses for Ivanpah.
Impairment losses on investments
Impairment losses on investments of $18 million were recorded during the sixthree months ended June 30,March 31, 2020 related to the impairment of Petra Nova Parish Holdings, as further discussed in Note 8, Impairments.
Other Income, Net
Other income increased by $9 million for the six months ended June 30, 2020, compared to the same period in 2019, driven primarily by income from insurance proceeds received of $11 million in 2020 and an increase in pension and postretirement income, partially offset by decreases in interest income and dividends received from cost method investments in 2020.
Loss on Debt Extinguishment
A loss on debt extinguishment of $47 million was recorded during the six months ended June 30, 2019, driven by the redemption of the 2024 Senior Notes and the repayment of the 2023 Term Loan Facility.
Interest Expense
Interest expense decreasedincreased by $26$29 million for the sixthree months ended June 30, 2020,March 31, 2021, compared to the same period in 2019,2020, primarily due to financings entered into in connection with the following:Direct Energy acquisition.
| | | | | |
| (In millions) |
Decrease related to the debt reduction of $600 million and refinancing $1.8 billion of debt at lower interest rates in 2019 | $ | (14) | |
Decrease in derivative interest expense due to the termination of interest rate swaps in 2019 | (8) | |
| |
Other | (4) | |
| |
Decrease in interest expense | $ | (26) | |
Income Tax (Benefit)/Expense
For the sixthree months ended June 30,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 $124$23 million was recorded on pre-tax income of $558 million. For the same period in 2019, income tax expense of $3 million was recorded on a pre-tax income of $286$144 million. The effective tax rates were 22.2%50.9% and 1.0%16.0% for the sixthree months ended June 30,March 31, 2021 and 2020, and 2019, respectively.
For the sixthree months ended June 30, 2020, NRG's overallMarch 31, 2021, the effective tax rate was higher than the statutory rate of 21% primarily due to state tax expense partially offset bybenefits 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. For the same period in 2019, NRG's overall effective tax rate was lower that the statutory rate of 21% primarily due to the change in valuation allowancecompensation, partially offset by the current state tax expense.
Income from Discontinued Operations, Net of Income Tax
| | | | | | | | | | | | |
| | | Six months ended June 30, | | | |
(In millions) | | | | 2019 | | |
South Central Portfolio | | | | $ | 36 | | | |
Carlsbad | | | | 363 | | | |
GenOn | | | | 2 | | | |
Income from discontinued operations, net of income tax | | | | $ | 401 | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
For the six months ended June 30, 2019, NRG recorded income from discontinued operations, net of income tax of $401 million, as further described in Note 4, Acquisitions, Discontinued Operations and Dispositions.
Liquidity and Capital Resources
Liquidity Position
As of June 30, 2020March 31, 2021 and December 31, 2019,2020, NRG's total liquidity, excluding funds deposited by counterparties, of approximately $2.2$3.2 billion and $2.1$7.0 billion, respectively, was comprised of the following:
| | (In millions) | (In millions) | June 30, 2020 | | December 31, 2019 | (In millions) | March 31, 2021 | | December 31, 2020 |
| Cash and cash equivalents | Cash and cash equivalents | $ | 418 | | | $ | 345 | | Cash and cash equivalents | $ | 501 | | | $ | 3,905 | |
| Restricted cash - operating | Restricted cash - operating | 4 | | | 4 | | Restricted cash - operating | 13 | | | 3 | |
Restricted cash - reserves(a) | Restricted cash - reserves(a) | 4 | | | 4 | | Restricted cash - reserves(a) | 5 | | | 3 | |
| Total | Total | 426 | | | 353 | | Total | 519 | | | 3,911 | |
| Total credit facility availability | 1,782 | | | 1,794 | | |
Total availability under Revolving Credit Facility and collective collateral facilities(b) | | Total availability under Revolving Credit Facility and collective collateral facilities(b) | 2,724 | | | 3,129 | |
| Total liquidity, excluding funds deposited by counterparties | Total liquidity, excluding funds deposited by counterparties | $ | 2,208 | | | $ | 2,147 | | 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 sixthree months ended June 30, 2020,March 31, 2021, total liquidity, excluding funds deposited by counterparties, increaseddecreased by $61$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 June 30, 2020March 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 July 24, 2020,March 17, 2021, following Winter Storm Uri, Standard & Poor's upgradedplaced NRG's issuer credit rating and senior unsecured debtof BB+ on CreditWatch with negative implications. On March 19, 2021, Moody's changed NRG's rating outlook to stable from BB to BB+ with a stable outlook. The agencypositive. At the same time, Moody's affirmed NRG's senior secured debt rating at BBB-. In addition, Moody's reaffirmed NRG's corporate family rating of Ba1 with a positive outlook on July 24, 2020.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, SeniorRevolving 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 July 24, 2020,January 5, 2021, the Company entered into the Purchase Agreement with Centrica to acquireacquired 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 68 Canadian provinces. The acquisition will addincreased NRG's retail portfolio by over 3 million customers to NRG's business and build on and complementstrengthens its integrated model, enabling better matching of power generation with customer demand.model. It will also broadenbroadens the Company's presence in the Northeast and into states and locales where it doesdid not currently operate, supporting NRG's objective to diversify its business.
The Company will paypaid an aggregate purchase price of $3.6$3.625 billion in cash subject to aand an initial purchase price adjustment including a working capital adjustment.of $77 million. The Company expects to fundfunded 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 $2.4$2.9 billion in newly-issued secured and unsecured corporate debt and approximately $750 millionissued in convertible preferred stock or other equity-linked instruments.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 expects to increaseincreased its collectiveliquidity and collateral facilities by $3.5$3.4 billion through a combination of new letter of credit facilities and increaseincreases to theits existing Revolving Credit Facility.Facility, as further described in Note 4, Acquisitions and Dispositions.
Collateral Facility Increases
The acquisition is subject to approval by the shareholders of Centrica, as well as customary closing conditions, consents and regulatory approvals, including the expiration or termination of the applicable waiting period under the HSR Act, and the receipt of approvals or expiration of applicable waiting periods under the Federal Power Act and the Canadian Competition Act.
The acquisition is targeted to close by December 31, 2020. There are no assurances that the conditionsfollowing table presents increases to the consummation of the acquisition of Direct Energy will be satisfied, that Centrica will not seek or enter into an alternative transaction as discussed below, or that the acquisition of Direct Energy will be consummated on the terms agreed to, or at all.
Prior to the approval of the transaction by its shareholders, Centrica is permitted to respond to unsolicited acquisition proposals that constitute or are reasonably likely to lead to a superior proposal, and to engage in negotiations with, and provide information to, parties that submit these proposals. Centrica can terminate the Purchase Agreement to accept a superior proposal. In addition, the board of directors of Centrica can change its recommendation in favor of NRG's transaction if the failure to do so would be inconsistent with the fiduciary duties of the Centrica directors, in which case the Purchase Agreement would automatically terminate. In the event of a termination of the Purchase AgreementCompany's collective collateral facilities in connection with (i) Centrica's decision to accept a superior proposal, (ii) the failure to obtain Centrica shareholder approval, or (iii) a change of recommendation by the Centrica board, Centrica would be obligated to pay NRG a termination fee of approximately $30 million.Direct Energy acquisition.
NRG will be required to pay Centrica a termination fee of $180 million if the Purchase Agreement is terminated (i) by either Centrica or NRG because the transaction has not been completed by July 24, 2021 (as such date may be extended for two separate three month periods if necessary to obtain required regulatory approvals, through January 24, 2022), and at the time of termination all of the mutual conditions to the obligations of NRG and Centrica to close the acquisition, and all the conditions to NRG's obligations to close the acquisition, have been satisfied other than receipt of the required antitrust and competition approvals, (ii) by either Centrica or NRG if a governmental entity has issued a judgment with respect to an antitrust or competition law that permanently prohibits the completion of the transaction and the judgment has become final and non-appealable, (iii) by NRG if a governmental entity has imposed a condition on its willingness to approve the acquisition on antitrust or competition grounds and the condition has a material adverse effect as described in the Purchase Agreement or (iv) by Centrica because NRG has breached its obligations under the Purchase Agreement to seek to obtain the antitrust and competition approvals required to complete the transaction. | | | | | |
| (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 | |
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 $83$750 million outstanding under its Revolving Credit Facility as of DecemberMarch 31, 2019, which was used to repay2021.
Sale of Agua Caliente
On February 3, 2021, the outstanding indebtednessCompany closed on the sale of its 35% ownership in the Agua Caliente Borrower 1 notessolar 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 leverage-neutral basis duringdefinitive 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 2019. Due2021, and is subject to marketvarious closing conditions, primarily asapprovals 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 COVID-19, the Company drew upon the facility in the first quarter of 2020 as a precaution and to proportionally increase cash on hand, and fully repaid the outstanding borrowings during the second quarter of 2020.
Midwest Generation Lease Purchase
On July 22, 2020, Midwest Generation signed purchase agreements to acquire allPart IV, Item 15 of the ownership interests in the Powerton facility and Units 7 and 8 of the Joliet facility, which were being leased through 2034 and 2030, respectively, for approximately $260 million. The Company intends to fund the purchase with borrowings under its Revolving Credit Facility in an amount equal to the existing operating lease liabilities of $148 million as of June 30,Company’s 2020 and the remainder from cash-on-hand. The closing is conditioned, among other items, on the receipt of regulatory approvals from FERC and under the HSR Act.Form 10-K.
Marketing of Agua Caliente
NRG renewed its efforts to sell its 35% interest in Agua Caliente in July 2020, following PG&E's emergence from bankruptcy.55
COVID-19CARES Act
On March 27, 2020, the U.S. government enacted the CARES Act, which provides, among other things,things: (i) the option to defer payments of certain 2019 employer payroll taxes incurred after the date of enactmentenactment; and pension contributions due in(ii) allows NOLs from tax years 2018, 2019 and 2020 as well as claim a refund now for AMT credits from the IRS that were previously refundable over severalto be carried back five years. As a result,The total benefit to the Company (i) expectsdue to defer the payment of approximately $17CARES Act was $35 million. Of this amount, $13 million for the employer share ofwill be payable to social security taxes that would otherwise have been due in 2020, with 50% due by December 31, 2021 and the remaining 50% due by December 31, 2022, (ii)$13 million will consider deferring until January 1, 2021 approximately $47 million of cash contributions to the Company’s pension plans previously planned to be madepayable in 2020 and (iii) received $34 million of refundable AMT credits on August 4, 2020, inclusive of $17 million that was originally scheduled to be received in 2021. Of the amount received, $11 million is due to GenOn for their share of the AMT credits.2022.
Tax-Exempt Bonds
On March 11, 2020, NRG issued $59 million in aggregate principal amount of NRG Dunkirk 2020 1.30% tax-exempt refinancing bonds due 2042 ("the Bonds"). The Bonds are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement. The Bonds are secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors. The collateral securing the Bonds will, at the request of NRG, be released if NRG satisfies certain conditions, including receipt of an investment grade rating on its senior, unsecured debt securities from two out of the three rating agencies, subject to reversion if those rating agencies withdraw their investment grade rating of the Bonds or any of NRG’s senior, unsecured debt securities or downgrade such rating below investment grade. The Bonds are subject to mandatory tender and purchase on April 3, 2023 and have a final maturity date of April 1, 2042.
NRG used the net proceeds from the offering to redeem the existing principal amount of outstanding Dunkirk Power LLC 5.875% tax exempt bonds due 2042.
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 June 30, 2020,March 31, 2021, the Company had total cash collateral outstanding of $136$286 million and $804$2,280 million outstanding in letters of credit to third parties primarily to support its market activities. As of June 30, 2020,March 31, 2021, total funds deposited by counterparties were $36$42 million in cash and $133$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, excludingsubject 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. To the extent that the underlying hedge positions for a counterparty are out-of-the-money to NRG, the counterparty would have a claim under the first lien program. The first lien program limitsdoes not limit the volume that can be hedged, notor 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. Within the first lien structure, the Company can hedge up to 80% of its coal and nuclear capacity, and 10% of its other assets, with these counterparties for the first 60 months and then declining thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.
The Company's first lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of June 30, 2020,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 June 30, 2020:March 31, 2021:
| Equivalent Net Sales Secured by First Lien Structure(a) | Equivalent Net Sales Secured by First Lien Structure(a) | 2020 | | 2021 | | 2022 | | 2023 | Equivalent Net Sales Secured by First Lien Structure(a) | 2021 | | 2022 | | 2023 | | 2024 |
| In MW | In MW | 401 | | 694 | | 692 | | 699 | In MW | 590 | | 714 | | 710 | | — |
As a percentage of total net coal and nuclear capacity(b) | As a percentage of total net coal and nuclear capacity(b) | 9% | | 15% | | 15% | | 15% | 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 sixthree months ended June 30, 2020,March 31, 2021, and the estimated capital expenditures forecast for the remainder of 2020.2021.
| | | | | | | | | | | | | | | | | | | | | | | |
| (In millions) | Maintenance | | Environmental | | Growth Investments(a) | | Total |
| Texas | $ | (52) | | | $ | — | | | $ | (13) | | | $ | (65) | |
| East | (7) | | | (1) | | | (7) | | | (15) | |
| West/Other | (19) | | | — | | | — | | | (19) | |
| Corporate | (4) | | | — | | | (13) | | | (17) | |
| Total cash capital expenditures for the six months ended June 30, 2020 | (82) | | | (1) | | | (33) | | | (116) | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Other investments(b) | — | | | — | | | (7) | | | (7) | |
| Total capital expenditures and investments, net of financings | (82) | | | (1) | | | (40) | | | (123) | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Estimated capital expenditures for the remainder of 2020(c)(d) | $ | (88) | | | $ | (4) | | | $ | (71) | | | $ | (163) | |
| | | | | | | | | | | | | | | | | | | | | | | |
| (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 costsintegration.
Growth investments in East for the three months ended March 31, 2021 include the Astoria generating facility, for which the Company has proposed to achieve. Excludes Midwest Generation lease buyout
(b) Includes $3 millionreplace 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 asset retirement obligation payments
(c) Growth investments include costsARO payments. Demolition is underway and is expected to achieve associated withbe completed in the Transformation Plan
(d) Growth investments include $22 millionfirst half of capital expenditures for Encina2022. The Company expects to begin marketing the site improvementsin 2021.
Environmental Capital Expenditures
NRG estimates that environmental capital expenditures from 20202021 through 20242025 required to comply with environmental laws will be approximately $43$63 million.
Share Repurchases
The Company adopted in the fourth quarter of 2019 a long-term capital allocation policy that targets allocating 50% of cash available for allocation generated each year to growth investments and 50% to be returned to shareholders. The return of capital to shareholders is expected to be completed through the increased dividend, supplemented by share repurchases.
During the six months ended June 30, 2020, the Company completed $224 million of share repurchases at an average price of $33.05 per share, including $27 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuance.
Common Stock Dividends
Beginning inDuring the first quarter of 2020,2021, NRG increased the annual dividend to $1.20$1.30 from $0.12$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 $0.30$0.325 per share was paid on the Company's common stock during the three months ended June 30, 2020.March 31, 2021. On July 17, 2020,April 19, 2021, NRG declared a quarterly dividend on the Company's common stock of $0.30$0.325 per share, payable Auguston May 17, 20202021 to stockholders of record as of AugustMay 3, 2020.2021.
Cash Flow Discussion
The following table reflects the changes in cash flows for the comparative sixthree month periods:
| | | | | | | | | | | | | | | | | |
| Six months ended June 30, | | | | |
| (In millions) | 2020 | | 2019 | | Change |
| Net Cash Provided by Operating Activities | $ | 692 | | | $ | 425 | | | $ | 267 | |
| Net Cash (Used)/Provided by Investing Activities | (145) | | | 1,103 | | | (1,248) | |
| Net Cash Used by Financing Activities | (469) | | | (1,756) | | | 1,287 | |
| | | | | | | | | | | | | | | | | |
| 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) | 189 | |
Increase primarily due to decreased pension contributions in 2020 due to CARES Act deferrals and reduced commissions due to changes in sales channels as a result of COVID-19 | 76 | |
| 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 timingincreased 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 fuel shipments andDirect Energy, partially offset by an increase in purchases of renewable energy credit purchasescredits primarily due to the acquisition of Direct Energy. | 6764 | |
| Changes in cash collateral in support of risk management activities due to change in commodity prices | (67)(8) | |
Decrease in accounts receivable primarily driven by favorable days outstanding from the Texas retail portfolio | 32 | |
Decrease in cash provided by discontinued operations | (8) | |
Decrease in other working capital | (22) | |
| $ | 267 (1,125) | |
Net Cash (Used)/ProvidedUsed by Investing Activities
Changes to net cash (used)/provided by investing activities were driven by:
| | | | | |
| (In millions) |
DecreaseIncrease in proceeds from sales of assets and discontinued operations primarily due to sales of South Central and Carlsbad in 2019cash paid for acquisitions for Direct Energy | $ | (1,274)(3,482) | |
| Increase in proceeds from sale of assets primarily due to sale of Agua Caliente | 182 | |
Decrease in contributions to discontinued operations | 44 | |
Increase in purchases of investments in nuclear decommissioning trust fund securities, net of proceeds from sales | (19) | |
Decrease in cash paid for acquisitions | 16 | |
Increase in capital expenditures | (9)3 | |
| Other | (6)1 | |
| |
| |
| $ | (1,248)(3,296) | |
Net Cash UsedProvided by Financing Activities
Changes to net cash usedprovided/(used) by financing activities were driven by:
| | | | | |
| (In millions) |
DecreaseIncrease in payments of long-term debtproceeds from Revolving Credit Facility and Receivables Securitization Facilities | $ | 2,424273 | |
DecreaseIncrease in proceedsnet receipts from issuancesettlement of long-term debtacquired derivatives | (1,774)193 | |
| Decrease in payments for share repurchase activity | 846170 | |
| |
| |
| Increase in payments of dividends to common stockholders | (132)(6) | |
Repayment of Revolving Credit Facility | (83) | |
Decrease in payments of debt extinguishment costs and deferred issuance costs | 56 | |
Decrease in cash provided by discontinued operations | (43) | |
| Other | (7)1 | |
| $ | 1,287631 | |
NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740
For the sixthree months ended June 30, 2020,March 31, 2021, the Company had domestic pre-tax book incomeloss of $550$189 million and foreign pre-tax book income of $8$22 million. As of December 31, 2019,2020, the Company had cumulative domestic Federal NOL carryforwards of $10.1 billion, which will begin expiring in 2031, and cumulative state NOL carryforwards of $5.5$5.4 billion for financial statement purposes. NRG also has cumulative foreign NOL carryforwards of $357$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 localforeign jurisdictions, of up to $18$60 million in 2020.2021.
TheAs 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 of $18 million, inclusive(inclusive of accrued interest, for uncertain tax benefits taken on various state income tax positionsinterest) 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 2016.2017. With few exceptions, state and local income tax examinations are no longer open for years prior to 2011.2012.
Deferred tax assets and valuation allowance
Net deferred tax balance —– As of both June 30, 2020March 31, 2021 and December 31, 2019,2020, NRG recorded a net deferred tax asset, excluding valuation allowance, of $3.4 billion.$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 June 30, 2020March 31, 2021 as discussed below.
Valuation allowanceNOL Carryforwards —– As of June 30, 2020March 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, 2019,2020, the Company'sCompany’s tax-effected valuation allowance was $241$266 million, and $242 million, respectively, 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.
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 June 30, 2020,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 to this Form 10-Q..
NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $859$567 million as of June 30, 2020.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 20192020 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 20192020 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 and six months ended June 30, 2020.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
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. Historically,In addition, in order to mitigate interestforeign exchange rate risk associated with the issuancepurchase of USD denominated natural gas for the Company's variable rateCanadian 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 fixed rate debt, NRG entered into interest rate swap agreements. As of June 30, 2020, NRG had no interest rate derivative instruments. The following disclosures aboutchanges in the fair value of these derivative financial instruments provide an update to, and should be readare recognized in conjunction with, Fair Value of Derivative Instruments in Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations, of the Company's 2019 Form 10-K.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 June 30, 2020,March 31, 2021, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at June 30, 2020.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, 20192020 | $ | 67 (63) | |
| Contracts realized or otherwise settled during the period | 31150 | |
| Direct contracts acquired during the period | (283) | |
| Changes in fair value | 105580 | |
Fair Value of Contracts as of June 30, 2020March 31, 2021 | $ | 203384 | |
| | | Fair Value of Contracts as of June 30, 2020 | | | Fair Value of Contracts as of March 31, 2021 |
| (In millions) | (In millions) | Maturity | | (In millions) | Maturity |
| Fair value hierarchy (Losses)/Gains | 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 | 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 | Level 1 | $ | (53) | | | $ | (11) | | | $ | (1) | | | $ | 1 | | | $ | (64) | | Level 1 | $ | — | | | $ | (11) | | | $ | — | | | $ | 1 | | | $ | (10) | |
| Level 2 | Level 2 | 23 | | | 92 | | | 9 | | | (9) | | | 115 | | Level 2 | 179 | | | 52 | | | 10 | | | (6) | | | 235 | |
| Level 3 | Level 3 | 93 | | | 22 | | | 6 | | | 31 | | | 152 | | Level 3 | 31 | | | 27 | | | 30 | | | 71 | | | 159 | |
| Total | Total | $ | 63 | | | $ | 103 | | | $ | 14 | | | $ | 23 | | | $ | 203 | | Total | $ | 210 | | | $ | 68 | | | $ | 40 | | | $ | 66 | | | $ | 384 | |
The Company has elected to presentdisclose 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 paidposted 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 June 30, 2020,March 31, 2021, NRG's net derivative asset was $203$384 million, an increase to total fair value of $136$447 million as compared to December 31, 2019.2020. This increase was primarily driven by gains in fair value as well asand roll-off of trades that settled during the period, partially offset by Direct Energy contracts acquired during the period.
Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in an increase of approximately $166 million$1.309 billion in the net value of derivatives as of June 30, 2020. 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 $167 million$1.337 billion in the net value of derivatives as of June 30, 2020.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,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 20192020 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 20192020 Form 10-K. There have been no material changes to the Company's critical accounting policies and estimates since the 20192020 Form 10-K, except as noted below.
As part of perfecting the integrated model, in which the majority of the Company’s generation serves its retail customers, the Company began managing its operations based on the combined results of the retail and wholesale generation businesses with a geographical focus in 2020. As a result, the Company changed its business segments to Texas, East and West/Other beginning in the first quarter of 2020, as further described in Note 1, Nature of Business. As a result, the Company identified its reporting units as Texas (included in the Texas segment), East Retail (included in the East segment) and Midwest Generation (included in the East segment). The Company performed a quantitative assessment, using primarily an income approach, for each of the Company's new reporting units as of January 1, 2020. Under the income approach, the Company estimated the fair value of each reporting unit's cash flow exceeded its carrying value and, as such, the Company concluded that goodwill associated with each of the reporting units was not impaired as of January 1, 2020 as a result of the change in reporting units.10-K.
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 an existing or forecasted financial or commodity transaction.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 20192020 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.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, including generation assets, load obligations and bilateral physical and financial transactions, calculated using the VaR model for the three and six months ending June 30, 2020March 31, 2021 and 2019:2020:
| | | | | | | | | | | |
| (In millions) | 2020 | | 2019 |
| VaR as of June 30, | $ | 25 | | | $ | 33 | |
| Three months ended June 30, | | | |
| Average | $ | 26 | | | $ | 40 | |
| Maximum | 31 | | | 46 | |
| Minimum | 22 | | | 33 | |
| Six months ended June 30, | | | |
| Average | $ | 27 | | | $ | 43 | |
| Maximum | 47 | | | 49 | |
| Minimum | 22 | | | 33 | |
| | | | | | | | | | | |
| (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 $15$94 million, as of June 30, 2020,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 June 30, 2020,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 $180$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 $46$345 million. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of June 30, 2020.March 31, 2021.
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
NRG was previously exposed to fluctuations in interest rates through its issuance of variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG's risk management policies allow the Company to reduce interest rate exposure from variable rate debt obligations.
The Company previously entered into interest rate swaps. As of June 30, 2020, NRG had no interest rate derivative instruments.
As of June 30, 2020,March 31, 2021, the fair value and related carrying value of the Company's debt was $6.2$10 billion and $5.9$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 June 30, 2020March 31, 2021 by $510$718 million.
Currency Exchange Risk
NRG's foreign earnings and investments may beNRG 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 which NRG generally doesrelated 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 hedge. As these earnings and investments are nothave resulted in a material to NRG's consolidated results,difference within the Company's foreign currency exposure is limited.Consolidated Statement of Operations.
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 June 30, 2020March 31, 2021 that materially affected, or are reasonably likely to materially affect, NRG's internal control over financial reporting.
PART II — OTHER INFORMATION
ITEM 1 — LEGAL PROCEEDINGS
For a discussion of material legal proceedings in which NRG was involved through June 30, 2020,March 31, 2021, see Note 16, Commitments and Contingencies, to this Form 10-Q.
ITEM 1A — RISK FACTORS
Except as set forth below, duringDuring the sixthree months ended June 30, 2020,March 31, 2021, there were no material changes to the Risk Factors disclosed in Part I, Item 1A, Risk Factors, of the Company's 20192020 Form 10-K.
Public health threats or outbreaks of communicable diseases could have a material adverse effect on the Company’s operations and financial results.
The Company may face risks related to public health threats or outbreaks of communicable diseases. A widespread healthcare crisis, such as an outbreak of a communicable disease, could adversely affect the global economy and the Company’s ability to conduct its business for an indefinite period of time. For example, the ongoing global COVID-19 pandemic has negatively impacted local and global economies, disrupted financial markets and international trade, resulted in increased unemployment levels and impacted local and global supply chains, all of which negatively impact the electricity industry and the Company’s business. In addition, federal, state, and local governments have implemented various mitigation measures, including travel restrictions, border closings, restrictions on public gatherings, shelter-in-place orders and limitations on business activities. Although the operations of the Company are considered an essential service, some of these measures have adversely impacted the ability of NRG employees, contractors, suppliers, customers, and other business partners to conduct business activities. This could have a material adverse effect on the Company’s results of operations, financial condition, risk exposure and liquidity.
In particular, the continued spread of COVID-19 and efforts to contain the virus could:
•adversely impact demand for the Company’s electricity services and other products and services and the ability of customers to pay their bills;
•cause an increase in costs for the Company as a result of emergency measures taken by state and local regulatory authorities in response to the COVID-19 crisis, including regulatory changes prohibiting customer disconnects and late fees;
•impact the ability of the Company's partners or counterparties to perform their obligations under existing arrangements, including development projects, power purchase and sale arrangements, hedging arrangements or other commercial activities; and
•cause other unpredicted events which may have an adverse impact on the Company’s results of operations, financial condition, risk exposure and liquidity.
The situation surrounding COVID-19 remains fluid and the potential for a material impact on the Company’s results of operations, financial condition, risk exposure and liquidity increases the longer the virus impacts the level of economic activity in the United States and globally. NRG cannot reasonably estimate with any degree of certainty the future impact of COVID-19, or any resurgence of COVID-19 or other pandemic may have on the Company’s results of operations, financial position, risk exposure and liquidity.
Risks related to the proposed acquisition of Direct Energy
The Company may be unable to consummate the acquisition of Direct Energy because it may not be able to obtain the approvals necessary to do so, or the combined company may be required to comply with material restrictions or conditions that might impact the parties' interests in consummating the transaction.
On July 24, 2020, the Company entered into a definitive purchase agreement with Centrica to acquire its North American retail business, Direct Energy (the "Purchase Agreement"). Before the acquisition may be completed, Centrica will need to obtain shareholder approval in connection with the proposed transaction. In addition, the completion of the acquisition is conditioned on certain customary closing conditions, including the expiration or termination of the applicable waiting period under the HSR Act, and the receipt of approvals or expiration of applicable waiting periods under the Federal Power Act and the Canadian Competition Act. These governmental authorities may impose conditions on the completion, or require changes to the terms, of the transaction, including conditions on or changes to the business, or operations of the combined company following completion of the acquisition. These conditions or changes could impose additional costs on or limit the revenues or income of the combined company following the acquisition, which could have a material adverse effect on the financial results of the combined company and/or cause either NRG or Centrica to abandon the acquisition. In addition, the regulatory review
processes to be pursued in connection with the transaction, and any litigation that may arise from these processes or otherwise, may materially delay the closing of the acquisition.
Furthermore, prior to the approval of the transaction by its shareholders, Centrica is permitted to respond to unsolicited acquisition proposals that constitute or are reasonably likely to lead to a superior proposal, and to engage in negotiations with, and provide information to, parties that submit these proposals. As a result, Centrica can terminate the Purchase Agreement to accept a superior proposal.In addition, theboard of directors of Centrica can change its recommendation for the NRG transaction if the failure to do so would be inconsistent with the fiduciary duties of the Centrica directors, in which case the Purchase Agreement would automatically terminate
If the Company is unable to complete the acquisition, it will still incur and will remain liable for significant transaction costs, including financing, legal, accounting, filing, and other costs relating to the transaction. Also, if the transaction is not completed due to the failure to obtain antitrust or competition approvals for the acquisition, or the Company decides to terminate the transaction in accordance with the purchase agreement due to conditions imposed or sought to be imposed in connection with obtaining these approvals, the Company will be required to pay Centrica a termination fee of $180 million.
If completed, the acquisition of Direct Energy may not achieve its intended results.
The Company entered into the Purchase Agreement with the expectation that the acquisition would result in various benefits, including, among other things, cost savings and operating efficiencies. Achieving the anticipated benefits of the acquisition is subject to a number of uncertainties, including whether the businesses of NRG and Direct Energy are integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could result in increased costs, lower-than-expected revenues or income generated by the combined company and diversion of management's time and energy and could have an adverse effect on the Company's business, financial results and prospects.
The Company will be subject to business uncertainties and contractual restrictions while the acquisition of Direct Energy is pending that could adversely affect its financial results.
Uncertainty about the effects of the acquisition of Direct Energy on employees, customers and suppliers may have an adverse effect on NRG's business. Although the Company intends to take steps designed to reduce any adverse effects, these uncertainties may impair its ability to attract, retain and motivate key personnel until the acquisition is completed and for a period of time thereafter, and could cause customers, suppliers and others that deal with it to seek to change existing business relationships.
Employee retention and recruitment may be particularly challenging prior to the completion of the acquisition, as employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite the Company's retention and recruiting efforts, key employees depart or fail to accept employment with NRG because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, the Company's financial results could be affected.
The pursuit of the acquisition and the preparation for the integration of NRG and Direct Energy may place a significant burden on management and internal resources. The diversion of management attention away from ongoing business concerns and any difficulties encountered in the transition and integration process could affect the Company's business, results of operations and financial condition.
In addition, the Company is obligated under the Purchase Agreement to take all actions necessary to obtain antitrust and competition approvals for the acquisition, subject to its right not to take actions that would have a material adverse effect as described in the Purchase Agreement. If the antitrust and competition approvals required for the transaction are not obtained and either NRG or Centrica terminates the Purchase Agreement for this reason, the Company will be required to pay Centrica a termination fee of $180 million. In addition, the Company has agreed not to take any actions that would materially delay the satisfaction of any of the closing conditions to the transaction or prevent any of those conditions from being satisfied. This restriction on the Company's actions may prevent it from pursuing otherwise attractive business opportunities and making other changes to its business prior to completion of the acquisition or termination of the Purchase Agreement.
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
The table below sets forthDuring the information with respect toquarter 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), of NRG's common stock during the quarter ended June 30, 2020.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the three months ended June 30, 2020 | | Total Number of Shares Purchased(a) | | Average Price Paid per Share(b) | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(a) |
| Month #1 | | | | | | | | |
| (April 1, 2020 to April 30, 2020) | | 1,601,345 | | | $ | 29.33 | | | — | | | $ | — | |
| Month #2 | | | | | | | | |
| (May 1, 2020 to May 31, 2020) | | — | | | $ | — | | | — | | | $ | — | |
| Month #3 | | | | | | | | |
| (June 1, 2020 to June 30, 2020) | | — | | | $ | — | | | — | | | $ | — | |
| | | | | | | | |
| Total at June 30, 2020 | | 1,601,345 | | | $ | 29.33 | | | — | | | |
| | | | | | | | |
| | | | | | | | |
(a)The Company adopted in the fourth quarter of 2019 a long-term capital allocation policy that targets allocating 50% of cash available for allocation generated each year to growth investments and 50% to be returned to shareholders. The return of capital to shareholders is expected to be completed through the increased dividend beginning in 2020, supplemented by share repurchases made in open-market repurchases
(b)The average price per share excludes commissions of $0.02 per share paid in connection with the open-market share repurchases
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4 — MINE SAFETY DISCLOSURES
Not applicable.There have been no events that are required to be reported under this Item.
ITEM 5 — OTHER INFORMATION
None.
ITEM 6 — EXHIBITS
| | | | | | | | | | | | | | |
| Number | | Description | | Method of Filing |
2.12† | | Purchase and Sale Agreement dated as of July 24, 2020,February 28, 2021 by and between the Company, Parent, Centrica Beta Holdings Limited, Centrica Gamma Holdings Limited, Centrica US HoldingsNRG Energy, Inc., and Direct Energy Marketing Limited.Generation Bridge Acquisition, LLC, as a Purchaser | | Incorporated herein by reference to Exhibit 2.1 to the Registrant's Current Report on Form 8-K, filed on July 30, 2020.Filed herewith |
2.24.1 | | | | Filed herewith. |
| 4.2 | | | | Incorporated herein by reference to Exhibit 2.2 to the Registrant's Current Report on Form 8-K, filed on July 30, 2020.Filed herewith. |
| 4.3 | | | | Filed herewith. |
| 4.4 | | | | Filed herewith. |
| 4.5 | | | | Filed herewith. |
| 4.6 | | | | Filed herewith. |
| 4.7 | | | | Filed herewith. |
| 4.8 | | | | Filed herewith. |
| 4.9 | | | | Filed herewith. |
| 22.1 | | | | Filed herewith. |
| 31.1 | | | | Filed herewith. |
| 31.2 | | | | Filed herewith. |
| 31.3 | | | | Filed herewith. |
| 32 | | | | 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 “[***]”. |
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/ KIRKLAND B. ANDREWS GAËTAN FROTTÉ | | | |
| | Kirkland B. Andrews Gaëtan Frotté | | | |
| | Interim Chief Financial Officer (Principal Financial Officer) | | |
| |
| | | | | |
| | | | | |
| | /s/ DAVID CALLEN | | | |
| | David Callen | | | |
Date: AugustMay 6, 20202021 | Chief Accounting Officer (Principal Accounting Officer) | | | |
| | | | | |