What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2022-02-24 compared with 2021-03-01 · 490 added, 573 removed, 568 unchanged (65% of the section changed)

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The discussion and analysis below has been organized as follows:

• Executive Summary, including the business environment in which the Company operates, a discussion of regulation, weather, competition and other factors that affect the business, a Transformation Plan update, and other significant events that are important to understanding the results of operations and financial condition;

• Executive Summary, including the business environment in which the Company operates, a discussion of regulation, weather, competition and other factors that affect the business, and other significant events that are important to understanding the results of operations and financial condition;

• Results of operations for the years ended December 31, 2021 and December 31, 2020, including an explanation of significant differences between the periods in the specific line items of NRG's Consolidated Statements of Operations;

• Financial condition addressing credit ratings, liquidity position, sources and uses of cash, capital resources and requirements, commitments, and off-balance sheet arrangements;

• Critical accounting policies that are most important to both the portrayal of the Company's financial condition and results of operations, and require management's most difficult, subjective or complex judgments.

• Financial condition addressing credit ratings, liquidity position, sources and uses of cash, capital resources and requirements, contractual obligations and market commitments, and off-balance sheet arrangements;

• Critical accounting estimates that are most important to both the portrayal of the Company's financial condition and results of operations, and require management's most difficult, subjective, or complex judgments.

As you read this discussion and analysis, refer to NRG's Consolidated Statements of Operations in this Form 10-K, which present the results of the Company's operations for the years ended December 31, 2021 and 2020, and also refer to Item 1 to this Form 10-K for more detail discussion about the Company's business.

A discussion and analysis of fiscal year 2018 may be found in Part II, Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations of Exhibit 99.1 to the Current Report on Form 8-K, filed on May 7, 2020, which provides retrospectively revised historical financial information to correspond with the Company's current segment structure.

A discussion and analysis of fiscal year 2019 may be found in Part II, Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations of the Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

As further described in Item 15 — Note 4, Acquisitions, Discontinued Operations and Dispositions , to the Consolidated Financial Statements, the Company determined in prior years that the following businesses were discontinued operations and recast to present their results in the corporate segment:

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and its Renewables Platform

• GenOn Energy, Inc.

Executive Summary

NRG is an integrated power company built on dynamic retail brands with diverse generation assets.

NRG brings the power of energy to customers by producing and selling energy and related products and services in major competitive power and gas markets in the U.S.

NRG Energy, Inc., or NRG or the Company, is a consumer services company built on dynamic retail brands.

NRG brings the power of energy to customers by producing and selling energy and related products and services, nation-wide in the U.S.

and Canada in a manner that delivers value to all of NRG's stakeholders.

As of December 31, 2020, the Company sold 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.

For discussion of COVID-19 related considerations refer to Item 1 — Business.

NRG sells power, natural gas, home and power services, and develops innovative, sustainable solutions, predominately under the brand names NRG, Reliant, Direct Energy, Green Mountain Energy, Stream, and XOOM Energy.

The Company has a customer base that includes approximately 6 million Home customers as well as commercial, industrial, and wholesale customers, supported by approximately 18,000 MW of generation as of December 31, 2021.

Business Environment

The industry dynamics and external influences affecting the Company, its businesses, and the retail energy and power generation industry in 2021 and for the future medium term include:

Commodities Markets — The price of natural gas plays an important role in setting the price of electricity in many of the regions where NRG operates.

Market Dynamics — The price of natural gas plays an important role in setting the price of electricity in many of the regions where NRG operates.

Natural gas prices are driven by variables including demand from the industrial, residential, and electric sectors, productivity across natural gas supply basins, costs of natural gas production, changes in pipeline infrastructure, and the financial and hedging profile of natural gas customers and producers.

In 2020, the average natural gas prices at Henry Hub was 21% lower than in 2019.

If long-term gas prices increase, the Company is likely to encounter higher realized energy prices, leading to higher energy revenues as lower priced hedge contracts mature and are replaced by contracts with higher gas and power prices.

This impact is partially offset by the retail operations, as NRG's retail gross margins have historically decreased as natural gas prices increase.

NRG's retail gross margins have historically improved as natural gas prices decline.

This would be partially offset by lower realized energy prices, leading to lower energy revenues as higher priced hedge contracts mature and are replaced by contracts with lower gas and power prices.

To further mitigate this impact, NRG may increase its percentage of coal and nuclear capacity sold forward using a variety of hedging instruments, as described under the heading "Energy-Related Commodities" in Item 15 — Note 6, Accounting for Derivative Instruments and Hedging Activities, to the Consolidated Financial Statements.

In 2021, the average natural gas price at Henry Hub was 85% higher than in 2020.

NRG may experience impacts to gross margins due to significant, rapid changes in current natural gas prices and the lag in our ability to make a corresponding adjustment to the retail rates we charge customers on term and month to month contracts.

The Company hedges its load commitments in order to mitigate the impact of changes in commodity prices, and as a result, these gross margin impacts would be realized in future periods until we are able to make the corresponding adjustments to the retail customer rates.

Natural gas prices are a primary driver of coal demand.

The low-priced commodity environment has stressed coal equities, leading coal suppliers to file for bankruptcy protection, launch debt exchanges, rationalize assets, and cut production.

If multiple parties withdraw from the market, liquidity could be challenged in the short term.

Inventory overhang will be utilized to offset production losses.

Coal prices are typically affected by the price of natural gas.

Coal commodity prices increased significantly in 2021, which is partly due to supply chain disruptions, as further discussed below in Global Supply Chain Disruptions , as well as stressed coal equities, which has led coal suppliers to file for bankruptcy protection, launch debt exchanges, rationalize assets, and cut production.

Electricity Prices — The price of electricity is a key determinant of the profitability of the Company.

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The following table summarizes average on-peak power prices for each of the major markets in which NRG operates for the years ended December 31, 2021 and 2020.

ERCOT power prices decreased for the year ended December 31, 2020 as compared to 2019 primarily due to the lower power prices in summer and lower gas prices in the first half of the year.

Power prices in the East and West/Other decreased for the year ended December 31, 2020 as compared to 2019 due to lower prices associated with lower demand due to COVID-19.

The average on-peak power prices increased significantly in Texas due to the impact from Winter Storm Uri.

The average on-peak power prices increased in East and West/Services/Other due to higher natural gas prices.

Average On-Peak Power Price ($/MWh)

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(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 each region in which NRG operates, including the impact of settled hedges, for the years ended December 31, 2020 and 2019:

The following table summarizes average realized power prices for NRG, including the impact of settled hedges, for the years ended December 31, 2021 and 2020:

Average Realized Power Price ($/MWh)

Year Ended December 31, 2021 vs 2020

Region 2020 2019 Change %

East $ 34.92 $ 34.37 2 %

West/Other 34.80 32.41 7 %

(a) Average Realized Power Price reflects energy sales from the generation fleet, omitting sales to the retail component of the East Segment.

Segment 2021 2020 Change %

$ 36.33 $ 34.92 4 %

West/Services/Other 43.63 34.80 25 %

(a) Average Realized Power Price reflects energy sales from the generation fleet, including sales to the retail component of the East Segment.

Intercompany financial transactions hedging generation with the retail operations make up ($8.03)/MWh in the year ended December 31, 2021 and $12.18/MWh in the year ended December 31, 2020

The average realized power prices were relatively stable year over year due to the Company's hedging program.

The average realized power prices increased less than average on peak power prices for the year ended December 31, 2021, as compared to the same period in 2020, due to the Company's multi-year hedging program impacting average realized power prices, while on peak power prices increased due to increased natural gas prices and warmer June temperatures in California.

Increased Awareness of, and Action to Combat, Climate Change — Diverse groups of stakeholders, including investors, asset managers, financial institutions, non-government organizations, industry coalitions, individual companies, consumer groups and academic institutions, are increasingly engaged in efforts to limit global warming in the post-industrial era to well below 2 degrees Celsius.

As a result, policymakers and regulators at regional, national, sub-national and local levels of government, both in the United States and other parts of the world, are increasingly focused on actions to combat climate change.

In the United States, the current Administration has stated that limiting climate change is one of its top priorities.

In its early days, the Administration issued an Executive Order on "Tackling the Climate Crisis at Home and Abroad." This included commitments to reset the United States' greenhouse gas emission reduction targets under the Paris Climate Agreement, integrate environmental justice considerations into all aspects of its climate and environmental policy, consider climate change and conservation in federal permitting decisions and align government procurement strategy and standards with climate goals.

To enable climate policy development and implementation, the Administration has pledged to adopt a "whole-of-government" approach and is establishing various new climate-oriented positions and working groups.

For example, it created the White House Office of Domestic Climate Policy, led by the first-ever National Climate Advisor and Deputy National Climate Advisor, which will create a central office in the White House that is charged with coordinating and implementing the President's domestic climate agenda.

The newly established National Climate Task Force will assemble representatives from across 21 federal agencies and departments.

The Federal Reserve is creating a committee to deepen its understanding of the risks that climate change poses to the financial system.

The SEC has created the new role of Senior Policy Advisor for Climate and Environmental, Social and Governance ("ESG") to oversee and coordinate the agency's efforts related to climate risk and other ESG developments, and to examine how these issues intersect with the regulatory framework across its offices and divisions.

An interagency working group on Coal and Power Plant Communities and Revitalization will identify and deliver federal resources to revitalize the economics of coal, oil, gas and power plant dependent communities.

Outside the United States, a foreign climate agenda will be advanced through the Special Presidential Envoy for Climate in concert with departments including State and Treasury.

NRG actively monitors climate change related developments that could impact its business and regularly engages with a diverse set of stakeholders on these issues.

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NRG is committed to providing transparent disclosures of its climate risks and opportunities to stakeholders.

The Company became an early supporter of the Task Force on Climate-related Financial Disclosures ("TCFD") recommendations after they were issued in 2017, published a TCFD mapping disclosure in December 2020 and will issue a stand-alone TCFD report in 2021.

Lower Carbon Infrastructure Development — Policy mechanisms at the state and federal level, including production and investment tax credits, cash grants, loan guarantees, accelerated depreciation tax benefits, RPS, and carbon trading plans, have supported and continue to support the development of renewable generation, demand-side and smart grid, and other lower carbon infrastructure technologies.

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These factors continue to drive increases in the development of lower carbon infrastructure in the markets where the Company participates, which may impact the ability of the Company's generating facilities to participate in those markets.

According to ERCOT, Inc., 36% of 2020 energy consumption in the ERCOT market was generated from carbon emission-free resources, with wind power contributing 23%.

According to ERCOT, 39% of 2021 energy consumption in the ERCOT market was generated from carbon emission-free resources, with wind power contributing 24%.

In addition, subsidies and incentives have contributed to the increase in renewable power sources, and customer awareness and preferences are shifting toward sustainable solutions.

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Weather — Weather conditions in the regions of the U.S.

in which NRG does business influence the Company's financial results.

in which NRG conducts business influence the Company's financial results.

Weather conditions can affect the supply and demand for electricity and fuels and may also impact the availability of the Company's generating assets.

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A significant portion of the Company's business is located within Texas, and extreme weather conditions occurring in Texas may have a material impact on the Company's financial position.

For discussion of the recent weather event in Texas, see Other Significant Events - Extreme Weather Event in Texas During February 2021 below.

For discussion of the recent weather event in Texas, see Significant Events - Extreme Weather Event in Texas During February 2021 and expected Uplift Securitization Proceeds below.

Global Supply Chain Disruptions — There are currently global supply chain disruptions impacting natural gas, coal and other fuels and materials necessary for the production and sale of electricity to our retail customers.

These supply chain disruptions are due in part to increased demand driven by a number of factors outside the Company's control including the COVID-19 pandemic, labor shortages and extreme weather events in the U.S.

These factors are impacting the dispatch of generation facilities, as well as the costs to serve our retail customers.

The Company expects supply chain disruptions will continue throughout the remainder of 2022.

We are working closely with our suppliers and customers to minimize any potential adverse impacts of these events.

We will continue to actively monitor all direct and indirect potential impacts of the supply chain disruptions, and will seek to mitigate and minimize their impact on our business.

Other Factors — A number of other factors significantly influence the level and volatility of prices for energy commodities and related derivative products for NRG's business.

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Some of this information relates to costs that may be material to the Company's financial results.

Transformation Plan

NRG completed its three-year Transformation Plan as of December 31, 2020.

The Transformation Plan targets were achieved as follows:

• Achieved recurring cost savings and margin enhancement of $1,065 million, including $590 million of cumulative cost savings, a $215 million net margin enhancement program, $50 million annual reduction in maintenance capital expenditures, and $210 million in permanent selling, general and administrative expense reduction associated with asset sales

• Fully realized $370 million of non-recurring working capital improvements and $295 million of one-time costs to achieve

• Completed asset sales of $3.0 billion, accomplishing the planned portfolio optimization

• Initially targeted credit ratio of 3.0x net debt / adjusted EBITDA (a) was achieved.

The credit metrics target was subsequently revised and successfully completed, to further strengthen its balance sheet and improve credit ratings by reducing leverage

(a) adjusted EBITDA as defined per the Senior Credit Facility

Other Significant Events

The following additional significant events occurred during 2020 and through the filing date:

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 GWs (without load shed).

Significant Events

The following significant events occurred during 2021 and through the filing date, as further described within this Management's Discussion and Analysis and the consolidated financial statements:

Financing Activities

On August 23, 2021, the Company issued $1.1 billion of aggregate principal amount at par of 3.875% senior notes due 2032 (the "2032 Senior Notes").

The 2032 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries.

The 2032 Senior Notes were issued under NRG's Sustainability-Linked Bond Framework, which sets out certain sustainability targets, including reducing greenhouse gas emissions.

Failure to meet such sustainability targets will result in a 25 basis point increase to the interest rate payable on the 2032 Senior Notes from and including August 15, 2026.

During the year ended December 31, 2021, the Company redeemed $1.9 billion in aggregate principal of its Senior Notes for $1.9 billion using the proceeds of the 2032 Senior Notes and cash on hand.

Extreme Weather Event in Texas During February 2021 and expected Uplift Securitization proceeds

During February 2021, Texas experienced unprecedented cold temperatures for a prolonged duration as a result of Winter Storm Uri, resulting in a power emergency, blackouts, and an estimated all-time peak demand of 77 GW (without load shed).

Ahead of the event, NRG launched residential customer communications calling for conservation across all of its brands, and initiated residential and commercial and industrial demand response programs to curtail customer load.

The Company maximized available generating capacity and brought in additional resources to supplement in-state staff with technical and operating experts from the rest of its U.S.

NRG is committed to working with all necessary stakeholders on a comprehensive, objective, and exhaustive root cause analysis of the entirety of the energy system.

The estimated financial impact is still preliminary, due to customer meter and settlement data not being finalized, as well as potential customer and counterparty risk and expected ERCOT default allocations.

Based on a preliminary analysis, Winter Storm Uri's financial impact is not expected to be adverse to NRG's financial results.

The Company separately stress-tested assumptions and although at a lower probability, this stress-test analysis indicated a potential plus or minus $100 million to income from continuing operations in 2021.

NRG's integrated platform continues to deliver stable results through unprecedented events.

The Texas Legislature passed House Bill 4492, which among other things, authorized ERCOT to obtain $2.1 billion of financing to distribute to LSEs that were charged and paid to ERCOT exceptionally highly priced ORDPA and ancillary service costs during Winter Storm Uri.

Based on LSE-level detail published by the PUCT on December 7, 2021, NRG will receive $689 million from ERCOT.

During the year ended December 31, 2021, Winter Storm Uri's pre-tax financial impact to the Company was a loss of $380 million, which reflects the recovery of $689 million of cost of operations as a result of the proceeds we will receive from the Uplift Securitization discussed above, with receipt expected to occur during the second quarter of 2022.

The Company continues to pursue additional mitigants including, but not limited to, customer bad debt mitigation, counterparty default recovery, and additional ERCOT default recovery.

Direct Energy Acquisition

On January 5, 2021, the Company acquired Direct Energy, a North American subsidiary of Centrica plc.

On January 5, 2021, the Company acquired Direct Energy, which had been a North American subsidiary of Centrica.

Direct Energy is a leading retail provider of electricity, natural gas, and home and business energy related products and services in North America, with operations in all 50 U.S.

states and 8 Canadian provinces.

The acquisition increases NRG's retail portfolio by over 3 million customers and complements its integrated model.

It also broadens the Company's presence in the Northeast and into states and locales where it does not currently operate, supporting NRG's objective to diversify its business.

The Company paid an aggregate purchase price of $3.625 billion in cash, subject to a purchase price adjustment of $77 million.

The Company funded the purchase price using a combination of $715 million of cash on hand, $166 million from a draw on its Revolving Credit Facility (of which $107 million was used to fund acquisition costs and financing fees that are not included in the aggregate purchase price above) as well as approximately $2.9 billion in secured and unsecured corporate debt issued in December 2020.

The Company also increased its collective collateral facilities by $3.4 billion through a combination of amending its Revolving Credit Facility, amending its credit default swap facility, entering into a revolving accounts receivable financing facility, entering into an uncommitted repurchase facility and entering into multiple agreements to issue letters of credit.

For further discussion on the increase of collateral facilities, see Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, Liquidity and Capital Resources, Item 15 — Note 13, Receivables Securitization and Repurchase Facility, and Item 15 — Note 14, Long-term Debt and Finance Leases.

Issuance of 2029 Senior Unsecured Notes and 2031 Senior Unsecured Notes

On December 2, 2020, NRG issued $500 million aggregate principal amount of 3.375% senior notes due 2029 (the "2029 Unsecured Notes") and $1.0 billion aggregate principal amount of 3.625% senior notes due 2031 (the "2031 Unsecured Notes, together with the 2029 Unsecured Notes, the "Unsecured Notes").

Issuance of 2025 and 2027 Senior Secured First Lien Notes

On December 2, 2020, NRG issued $1.4 billion of aggregate principal amount of senior secured first lien notes, consisting of $500 million 2.000% senior secured first lien notes due 2025 (the "2025 Secured Notes") and $900 million 2.450% senior secured first lien notes due 2027 (the "2027 Secured Notes"), at a discount.

The 2027 Secured Notes were issued under NRG’s Sustainability-Linked Bond Framework, which links attractive financing terms with the realization of certain sustainability targets, including reducing greenhouse gas emissions.

Receivables Securitization and Repurchase Facility

On September 22, 2020, NRG Receivables LLC, a bankruptcy remote, special purpose, indirect wholly owned subsidiary, entered into a revolving accounts receivable financing facility (the "Receivables Facility") for an amount up to $750 million, subject to adjustments on a seasonal basis, with issuers of asset-backed commercial paper and commercial banks (the "Lenders".) As of December 31, 2020, there were no outstanding borrowings and there were $198 million in letters of credit issued under the Receivables Facility.

On September 22, 2020, the Company entered into an uncommitted repurchase facility (the “Repurchase Facility”) related to the Receivables Facility.

Under the Repurchase Facility, the Company can borrow up to $75 million, collateralized by a subordinated note issued by NRG Receivables LLC to NRG Retail LLC in favor of the originating entities representing a portion of the balance of receivables sold to NRG Receivables LLC under the Receivables Facility.

As of December 31, 2020, there were no outstanding borrowings under the Repurchase Facility.

For further discussion on the Receivables Facility and Repurchase Facility, see Note 9, Receivables Securitization and Repurchase Facility.

Midwest Generation Lease Purchase

On September 29, 2020, Midwest Generation acquired all of the ownership interests in the Powerton facility and Units 7 and 8 of the Joliet facility, which were being leased through 2034 and 2030, respectively, for approximately $260 million.

The purchase was funded with cash-on-hand.

Upon closing, lease expense related to these facilities, which totaled approximately $14 million in 2019, and the operating lease liability of $148 million were eliminated.

Home Solar Disposition

In the third quarter of 2020, the Company concluded its Home Solar business was held for sale and recorded an impairment loss of $29 million.

On November 13, 2020, the Company completed the sale of the Home Solar business for cash proceeds of $66 million, resulting in a $2 million loss on the sale.

In connection with the sale, the Company extinguished debt of $27 million and recognized a $5 million loss on the extinguishment.

The acquisition increased NRG's retail portfolio by over 3 million customers and complements its integrated model.

It also broadened the Company's presence in the Northeast and into states and locales where it did not previously operate, supporting NRG's objective to diversify its business.

See Item 15 — Note 4, Acquisitions, Discontinued Operations and Dispositions , to the Consolidated Financial Statements for further discussion.

Limestone Extended Outage

In early July 2021, Limestone Unit 1 came offline as a result of damage to the duct work associated with the flue gas desulfurization system.

Based on management's current assessment of necessary remediation efforts, Limestone Unit 1 is expected to remain on an outage until the second quarter of 2022.

PJM Base Residual Auction results and Planned Retirement of 1,600 MWs of PJM Coal Capacity

During the second quarter of 2021, the results of the PJM Base Residual Auction for the 2022/2023 delivery year were released, leading the Company to announce the near-term retirement of a significant portion of its PJM coal generating assets in June 2022.

On July 30, 2021, PJM identified reliability impacts resulting from the proposed deactivation of one of those assets, Indian River Unit 4.

On August 27, 2021 the Company notified PJM that it would continue operations at Indian River Unit 4 until the reliability upgrades identified by PJM were completed, provided that the unit receives a satisfactory and compensatory 'reliability must run' arrangement.

The Company recorded impairment losses of $271 million and $35 million on the PJM generating assets and Midwest Generation goodwill, respectively, in connection with the decline in PJM capacity prices and the near-term retirement dates of certain assets.

See Item 15 — Note 11, Asset Impairments to the Consolidated Financial Statements for further discussion.

The Company is continuing to evaluate the viability of the remaining PJM generating assets.

Sale of 4.8 GW of Fossil Generation Assets

On December 1, 2021, the Company sold approximately 4,850 MWs of fossil generating assets from its East and West regions of operations to Generation Bridge, an affiliate of ArcLight Capital Partners.

As part of the transaction, NRG entered into a tolling agreement for the 866 MW Arthur Kill plant in New York City through April 2025.

See Item 15 — Note 4, Acquisitions, Discontinued Operations and Dispositions , to the Consolidated Financial Statements for further discussion.

Sale of Agua Caliente

On November 19, 2020, the Company entered an agreement to sell its 35% ownership in Agua Caliente to Clearway Energy, Inc.

On February 3, 2021, the Company completed the sale of its 35% ownership in Agua Caliente to Clearway Energy, Inc.

for $202 million.

The sale of the 290 MW solar project closed on February 3, 2021.

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 MWs 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 Hart-Scott-Rodino.

NRG recognized a gain on the sale of $17 million, including cash disposed of $7 million.

Share Repurchases

In 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.

In December 2021, the Company's board of directors authorized the Company to repurchase $1.0 billion of its common stock.

Through December 31, 2021, the Company completed $53 million of share repurchases at an average price of $40.22 per share, including $9 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances.

Through February 24, 2022, an additional $82 million of share repurchases were executed at an average price of $40.26 per share, including $6 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances.

See Item 15 - Note 16, Capital Structure , to the Consolidated Financial Statements for additional discussion.

Renewable Power Purchase Agreements

NRG began execution of its strategy to procure mid to long-term generation through power purchase agreements in 2019.

As of December 31, 2020, NRG has entered into PPAs totaling approximately 1,800 MWs with third-party project developers and other counterparties.

The tenor of these agreements is an average between eleven and twelve years.

The Company's strategy is to procure mid to long-term generation through power purchase agreements.

As of December 31, 2021, NRG has entered into PPAs totaling approximately 2.6 GW with third-party project developers and other counterparties.

The average tenor of these agreements is twelve years.

The Company expects to continue evaluating and executing similar agreements that support the needs of the business.

Due to COVID-19, certain of these PPA contracts have been amended to allow for the delay of project completion dates from mid-2021 into 2022.

These amendments include improved terms for NRG.

The total GW entered into through PPAs may be impacted by contract terminations when they occur.

Dividend Increase

In the first quarter of 2020, NRG increased the annual dividend to $1.20 from $0.12 per share, as part of a long-term capital allocation policy adopted in the fourth quarter of 2019 that targets allocating 50% of cash available for allocation generated each year to growth investments and 50% to be returned to shareholders.

The return of capital to shareholders is expected to be completed through the increased dividend supplemented by share repurchases.

The long-term capital allocation policy targets an annual dividend growth rate of 7-9% per share in years subsequent to 2020.

In the first quarter of 2021, NRG increased the annual dividend to $1.30 from $1.20 per share.

In 2022, NRG further increased the annual dividend to $1.40 per share, representing an 8% increase from 2021.

The Company expects to target an annual dividend growth rate of 7-9% per share in subsequent years.

While the pandemic presented risks, as further described in Part II, Item 1A — Risk Factors of this Form 10-K, to the Company’s business, there was not a material adverse impact on the Company’s results of operations for the years ended December 31, 2021 and 2020.

Consolidated Results of Operations for the years ended December 31, 2021 and 2020

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Mark-to-market for economic hedging activities (164) 95 (259)

Contract amortization (30) — (30)

Other revenues (a)(b)

1,632 319 1,313

Total operating revenues 26,989 9,093 17,896

Operating Costs and Expenses

Cost of sales (c)

Cost of fuel 1,844 851 (993)

Purchased energy and other cost of sales (c)

19,766 4,069 (15,697)

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Other cost of operations 339 272 (67)

Total cost of operations 6,540 7,303 763

Cost of operations (excluding depreciation and amortization shown below) 20,482 6,540 (13,942)

Depreciation and amortization 785 435 (350)

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Selling, general and administrative costs 1,293 810 (483)

Reorganization costs — 23 23

Development costs 8 7 (1)

Provision for credit losses 698 108 (590)

Acquisition-related transaction and integration costs 93 23 (70)

Total operating costs and expenses 23,895 7,991 (15,904)

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Other income, net 63 67 (4)

Net loss on debt extinguishment (9) (51) 42

Loss on debt extinguishment, net (77) (9) (68)

Interest expense (485) (401) (84)

Total other expenses (482) (344) (138)

Income from Continuing Operations Before Income Taxes 761 786 (25)

Income tax expense/(benefit) 251 (3,334) 3,585

Income from Continuing Operations 510 4,120 (3,610)

Income from discontinued operations, net of income tax — 321 (321)

Income Before Income Taxes 2,859 761 2,098

Income tax expense 672 251 421

Net Income $ 2,187 $ 510 $ 1,677

Net income attributable to noncontrolling interests and redeemable noncontrolling interests — 3 (3)

Net Income Attributable to NRG Energy, Inc.

$ 510 $ 4,438 $ (3,928)

Business Metrics

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(a) Includes realized gains and losses from financially settled transactions

(b) Includes realized and unrealized trading gains and losses

(b) Includes trading gains and losses and ancillary revenues

The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emission credit amortization and depreciation and amortization.

Economic Gross Margin

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The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker.

Economic gross margin is defined as the sum of energy revenue, capacity revenue and other revenue, less cost of fuels and other cost of sales.

Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emission credit amortization, or other operating costs.

The tables below present the composition and reconciliation of gross margin and economic gross margin for the years ended December 31, 2020 and 2019 based on the Company's reportable segments:

Economic gross margin is defined as the sum of retail revenue, energy revenue, capacity revenue and other revenue, less cost of fuels, purchased energy and other cost of sales.

Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emission credit amortization, depreciation and amortization, operations and maintenance, or other costs of operations.

The tables below present the composition and reconciliation of gross margin and economic gross margin for the years ended December 31, 2021 and 2020:

Year Ended December 31, 2021

($ in millions, except otherwise noted) Texas East West/Other Corporate/Eliminations Total

($ in millions, except otherwise noted) Texas East West/Services/Other Corporate/Eliminations Total

Retail revenue $ 8,410 $ 11,862 $ 3,290 $ (1) $ 23,561

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Mark-to-market for economic hedging activities (3) (88) (86) 13 (164)

Contract amortization — (26) (4) — (30)

Other revenue 1,557 59 25 (9) 1,632

Operating revenue 6,309 2,354 434 (4) 9,093

Operating revenue (a)

10,293 13,033 3,653 10 26,989

Cost of fuel (1,424) (196) (224) — (1,844)

Purchased power (945) (507) (24) 6 (1,470)

Other costs of sales (a)(b)

Purchased energy and other costs of sales (b)(c)(d)

(6,108) (10,775) (2,882) (1) (19,766)

1 unchanged sentence

Contract and emission credit amortization 2 (28) (17) — (43)

Depreciation and amortization (331) (338) (88) (28) (785)

Gross margin $ 3,420 $ 3,499 $ 544 $ (32) $ 7,431

Mark-to-market for economic hedging activities, net 985 1,715 16 — 2,716

Contract and emission credit amortization (5) — — — (5)

Contract and emission credit amortization, net 2 (54) (21) — (73)

Depreciation and amortization (331) (338) (88) (28) (785)

Economic gross margin $ 2,764 $ 2,176 $ 637 $ (4) $ 5,573

(a) Includes capacity and emissions credits

(b) Includes $1,967 million and $10 million of TDSP expense in Texas and East, respectively

Business Metrics Texas East West/Other Total

Mass Market electricity sales volume (GWh) 38,473 10,221 48,694

C&I electricity sales volume (GWh) 17,928 1,596 19,524

Natural gas retail sales volumes (MDth) — 23,509 23,509

Average retail Mass Market customer count (in thousands) (a)

(a) Includes trading gains and losses and ancillary revenues

(b) Includes capacity and emissions credits

(c) Includes $2,648 million, $183 million and $1,033 million of TDSP expense in Texas, East, and West/Services/Other respectively

(d) Excludes depreciation and amortization shown separately

Business Metrics Texas East West/Services/Other Corporate/Eliminations Total

Home electricity sales volume (GWh) 42,397 14,108 2,252 — 58,757

Business electricity sales volume (GWh) 34,367 53,204 10,625 — 98,196

Home natural gas retail sales volumes (MDth) — 74,920 97,272 — 172,192

Business natural gas retail sales volumes (MDth) — 1,595,533 109,021 — 1,704,554

Average retail Home customer count (in thousands) (a)

3,055 1,844 962 — 5,861

Ending retail Mass Market customer count (in thousands) (a)

Ending retail Home customer count (in thousands) (a)

3,024 1,766 932 — 5,722

GWh sold 36,920 11,452 8,503 — 56,875

GWh generated (b)

GWh generated (b) (c)

36,920 7,494 7,949 — 52,363

(a) East represents combined electricity and natural gas customers

(b) Includes owned generation and excludes equity investments

(a) Home customer count includes recurring residential customers, services customers and municipal aggregations

(b) Includes owned and leased generation, excludes tolled generation and equity investments

(c) Includes 1,054 GWh and 2,445 GWh in East and West/Services/Other respectively that was sold to Generation Bridge in December 2021

Year Ended December 31, 2020

($ in millions, except otherwise noted) Texas East West/Other (a)

($ in millions, except otherwise noted) Texas East West/Services/Other (a)

Corporate/Eliminations Total

6 unchanged sentences

Cost of fuel (546) (151) (154) — (851)

Purchased power (1,557) (612) (13) 1 (2,181)

Other costs of sales (a)(b)

Purchased energy and other costs of sales (a)(b)(c)

(3,110) (876) (89) 6 (4,069)

1 unchanged sentence

Contract and emission credit amortization (5) — — — (5)

Depreciation and amortization (227) (138) (36) (34) (435)

Gross margin $ 2,210 $ 1,098 $ 251 $ (40) $ 3,519

1 unchanged sentence

Contract and emission credit amortization (5) — — — (5)

Depreciation and amortization (227) (138) (36) (34) (435)

Economic gross margin $ 2,651 $ 1,143 $ 290 $ (6) $ 4,078

1 unchanged sentence

(b) Includes $1,967 million and $10 million of electric TDSP charges for Texas and East, respectively

Business Metrics Texas East West/Other Total

Mass Market electricity sales volume (GWh) 38,958 9,918 — 48,876

C&I electricity sales volume (GWh) 18,976 1,214 — 20,190

Business Metrics Texas East West/Services/Other Corporate/Eliminations Total

Home electricity sales volume (GWh) 38,473 10,221 — — 48,694

Business electricity sales volume (GWh) 17,928 1,596 — — 19,524

Natural gas retail sales volumes (MDth) — 23,509 — — 23,509

Average retail Mass Market customer count (in thousands) (a)

Average retail Home customer count (in thousands) (a)

2,449 1,175 — — 3,624

Ending retail Mass Market customer count (in thousands) (a)

Ending retail Home customer count (in thousands) (a)

2,451 1,136 — — 3,587

GWh sold 31,385 8,136 9,569 — 49,090

GWh generated (b)

GWh generated (b)(c)

31,385 4,102 9,171 — 44,658

(a) East represents combined electricity and natural gas customers

(b) Includes owned generation and excludes equity investments

(a) Home customer count includes recurring residential customers and municipal aggregations

(b) Includes owned and leased generation, excludes tolled generation and equity investments

(c) Includes 1,192 GWh and 3,002 GWh in East and West/Services/Other respectively that was sold to Generation Bridge in December 2021

The table below represents the weather metrics for 2021 and 2020:

December 31, Quarters ended December 31, Quarters ended September 30, Quarters ended

June 30, Quarters ended

Weather Metrics Texas East West/Other (a)

Texas East West/Other (a)

December 31, Quarter ended

December 31, Quarter ended September 30, Quarter ended

June 30, Quarter ended

Weather Metrics Texas East West/Services/Other (a)

Texas East West/Services/Other (a)

2,960 1,275 1,877 386 91 185 1,589 784 1,134 899 362 521 86 38 37

5 unchanged sentences

HDDs 1,691 4,558 2,044 693 1,584 774 2 56 10 59 521 193 937 2,397 1,067

(a) The West/Other weather metrics are comprised of the average of the CDD and HDD regional results for the West - California and West - South Central regions

(a) The West/Services/Other weather metrics are comprised of the average of the CDD and HDD regional results for the West - California and West - South Central regions

(b) National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region.

1 unchanged sentence

The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period

Winter Storm Uri

The following impacts are further discussed in the related sections below:

(In millions)

Gross margin - Texas $ 88

Gross margin - East 146

Gross margin - West/Services/Other 13

Total gross margin 247

Operations and maintenance expense (2)

Selling, general and administrative costs (29)

Provision for credit losses (596)

Total impact to loss before income taxes $ (380)

The Company continues to pursue additional mitigants including, but not limited to, customer bad debt mitigation, counterparty default recovery, and additional ERCOT default recovery.

Gross margin and economic gross margin

Gross margin increased $83 million and economic gross margin increased $168 million for the year ended December 31, 2020, compared to the same period in 2019.

Gross margin increased $3.9 billion and economic gross margin increased $1.5 billion, both of which include intercompany sales, during the year ended December 31, 2021, compared to the same period in 2020.

The detail by segment is as follows:

(In millions)

Lower fuel and supply costs primarily due to $18 per MWh lower average power purchases in 2020 to serve the retail load, driven by purchasing incremental supply in 2019 at escalated prices above $1,000/MWh during periods of extreme weather during the third quarter;

partially offset by a reduction in sell back of excess supply in 2020 $ 540

Lower gross margin due to a decrease in net sales of generation to third parties, as the supply was utilized to serve the Company's retail load following the integration of the wholesale generation and retail operations with a geographical focus in 2020 (269)

Lower net revenue due to:

• lower volumes from attrition, customer mix, and reduced sales from direct and alternative sales channels due to the impact of COVID-19 of $212 million,

• lower net revenue rates driven by customer term, product, mix and the impact of COVID-19 of $0.76 per MWh or $43 million,

• decreased load of 1.1 TWhs from unfavorable weather of $89 million;

• partially offset by higher retail net revenue due to increased volumes from the acquisition of Stream in August 2019 of $231 million

Lower gross margin from market optimization activities (27)

Lower gross margin due to the sale of emissions in 2019 (13)

Higher gross margin due to Winter Storm Uri, primarily driven by hedging optimization, partially offset by the negative impact of an increase in unhedgeable ancillary and operating reserve demand curve, net of securitization proceeds of $689 million $ 88

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 280

Higher gross margin due to market optimization activities 9

Lower gross margin due to a 22% increase in overall average costs to serve the retail load, driven primarily by increases in power, ancillary, fuel costs and the effect of the current year Limestone Unit 1 extended forced outage, totaling $349 million, partially offset by higher net revenue primarily driven by increased net revenue rates as a result of changes in customer term, product and mix of $2.50 per MWh, or $156 million (193)

Lower net revenue due to a decrease in load of 834,000 MWhs from weather (72)

Lower net revenue due to attrition and customer mix (5)

Increase in economic gross margin $ 113

Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges

Increase in contract and emission credit amortization 14

Decrease in gross margin $ (72)

Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges 1,194

Decrease in contract and emission credit amortization 7

Increase in depreciation and amortization (104)

Increase in gross margin $ 1,210

(In millions)

Higher gross margin driven by a 43% increase in New York realized capacity prices $ 47

Higher gross margin due to increased volumes from the acquisition of Stream Energy in August 2019 33

Higher gross margin due to increased sales of portable solar and power products 24

Higher gross margin due to lower supply costs on contracted load 23

Higher gross margin due to lower supply costs of approximately $2.50 per MWh, or $21 million, driven by lower electricity and natural gas prices, partially offset by $19 million from lower volumes due to attrition and customer mix, and the impact of COVID-19 2

Lower gross margin due to a 6% decrease in PJM capacity volumes and a 4% decrease in PJM capacity prices (41)

Lower gross margin due to a 25% decrease in New England realized capacity prices (36)

Lower gross margin due to a lower of cost or market adjustment on oil inventory in 2020 (29)

Lower gross margin primarily due to a 41% decrease in economic generation volumes, primarily due to dark spread contractions and planned outages in 2020 (16)

Lower gross margin due to insurance proceeds from outages in 2019 (8)

Economic gross margin $ —

Higher gross margin due to Winter Storm Uri, primarily driven by natural gas optimization during volatile pricing that occurred during the weather event $ 146

The following explanations exclude the impact of Winter Storm Uri:

Higher gross margin due to increased volumes from the acquisition of Direct Energy in January 2021, including $503 million from natural gas activity and $436 million from power activity 939

Higher business demand response gross margin primarily from the early settlement of capacity obligations in 2021 compared to the same period in 2020 of $63 million and higher volumes sold in 2021 of $10 million 73

Higher gross margin due to a lower of cost or market adjustment on oil inventory in 2020 29

Lower gross margin from higher supply costs of $8.25 per MWh, or $78 million and lower volumes due to attrition, weather and customer mix of $45 million, partially offset by higher revenue of $3 per MWh, or $29 million (94)

Lower gross margin due to a 20% decrease in average realized pricing primarily at Midwest Generation (39)

Lower gross margin due to the sale of fossil generating assets to Generation Bridge in December 2021

Lower gross margin from market optimization activities (5)

Increase in economic gross margin $ 1,033

Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges

Increase in contract amortization (54)

Increase in depreciation and amortization (200)

Increase in gross margin $ 2,401

West/Services/Other

(In millions)

Higher gross margin primarily due to MISO uplift payments resulting from out-of-market dispatch during Hurricane Laura, spark spread expansion in MISO and increased California resource adequacy pricing;

partially offset by lower realized pricing in the West $ 55

Higher gross margin from generation outage insurance proceeds received in 2020 for forced outages in 2019 30

Higher gross margin due to the extended forced outage at the Sunrise facility in 2019, partially offset by 2020 forced outages at Cottonwood 2

Higher gross margin due to Winter Storm Uri, driven by optimization during volatility in gas pricing $ 13

The following explanations exclude the impact of Winter Storm Uri:

Higher gross margin due to the acquisition of Direct Energy in January 2021 425

Lower gross margin primarily at Cottonwood driven by an 83% increase in fuel cost, partially offset by a 41% increase in realized power prices.

Lower gross margin primarily due to prior year MISO uplift payments resulting from out-of-market dispatch during Hurricane Laura (29)

Lower gross margin from generation outage insurance proceeds received in 2020 for forced outages in 2019, partially offset by Sunrise business interruption proceeds received in 2021 for forced outages in 2019 (22)

Lower gross margin from market optimization activities (9)

Lower gross margin due to the Canal 3 substantial completion payment earned in 2019 (9)

Lower gross margin due to the sale of emissions in 2019 (4)

Lower gross margin due to the sale of fossil generating assets to Generation Bridge in December 2021

Increase in economic gross margin $ 347

Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges

Increase in mark-to-market for economic hedges primarily due to net unrealized gains/losses on open positions related to economic hedges

Increase in contract amortization (21)

Increase in depreciation and amortization (52)

Increase in gross margin $ 293

1 unchanged sentence

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges.

Total net mark-to-market results decreased by $99 million during the year ended December 31, 2020, compared to the same period in 2019.

Total net mark-to-market results increased by $2.8 billion during the year ended December 31, 2021, compared to the same period in 2020.

The breakdown of gains and losses included in operating revenues and operating costs and expenses by segment was as follows:

Year Ended December 31, 2021

(In millions) Texas East West/Other Eliminations Total

(In millions) Texas East West/Services/Other Eliminations Total

Mark-to-market results in operating revenues

Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges

Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges

$ — $ (34) $ (4) $ (2) $ (40)

Net unrealized gains on open positions related to economic hedges

Total mark-to-market gains/(losses) in operating revenues

Reversal of acquired (gain) positions related to economic hedges — (6) — — $ (6)

Net unrealized (losses) on open positions related to economic hedges

(3) (48) (82) 15 (118)

Total mark-to-market (losses) in operating revenues

$ (3) $ (88) $ (86) $ 13 $ (164)

Mark-to-market results in operating costs and expenses

Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges

Reversal of previously recognized unrealized (gains) on settled positions related to economic hedges

$ (3) $ — $ — $ 2 $ (1)

Reversal of acquired loss positions related to economic hedges

Net unrealized (losses) on open positions related to economic hedges

Reversal of acquired loss/(gain) positions related to economic hedges

42 235 (15) — 262

Total mark-to-market (losses)/gains in operating costs and expenses

Net unrealized gains on open positions related to economic hedges

949 1,568 117 (15) 2,619

Total mark-to-market gains in operating costs and expenses

$ 988 $ 1,803 $ 102 $ (13) $ 2,880

Year Ended December 31, 2020

(In millions) Texas East West/Other Eliminations Total

(In millions) Texas East West/Services/Other Eliminations Total

Mark-to-market results in operating revenues

Reversal of previously recognized unrealized losses on settled positions related to economic hedges

$ 21 $ 14 $ 12 $ — $ 47

Net unrealized gains/(losses) on open positions related to economic hedges

Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges

$ 1 $ 33 $ (7) $ 4 $ 31

Net unrealized gains on open positions related to economic hedges

Total mark-to-market gains/(losses) in operating revenues

4 unchanged sentences

Reversal of acquired loss positions related to economic hedges.

Net unrealized gains/(losses) on open positions related to economic hedges

Net unrealized (losses) on open positions related to economic hedges

(126) (2) — (4) (132)

4 unchanged sentences

The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date.

For the year ended December 31, 2021 the $164 million loss in operating revenues from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of increases in East and West/Services/Other power prices, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period.

The $2.9 billion gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in the value of open positions as a result of increases in natural gas and power prices across all segments as well as the reversal of acquired contracts that settled during the year.

For the year ended December 31, 2020 the $95 million gain in operating revenues from economic hedge positions was driven primarily by an increase in the value of open positions as a result of decreases in New York capacity prices, as well as the reversal of previously recognized unrealized losses on contracts that settled during the period.

The $214 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of decreases in ERCOT power prices and heat rate contraction, as well as the reversal of previously recognized unrealized gains on contracts that settled during the period.

For the year ended December 31, 2019 the $33 million gain in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period.

The $53 million loss in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains, partially offset by an increase in the value of open positions as a result of 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 years ended December 31, 2021 and 2020.

9 unchanged sentences

Operations and maintenance expenses are comprised of the following:

(In millions) Texas East West/Other Corporate Eliminations Total

(In millions) Texas East West/Services/Other Corporate Eliminations Total

Year Ended December 31, 2021 $ 703 $ 452 $ 218 $ 2 $ (5) $ 1,370

2 unchanged sentences

(In millions)

Increase due to the final settlement of the asbestos liability related to Midwest Generation and the resulting reduction of the accrual in 2019 $ 27

Increase due to higher customer operations spend including digital capabilities, data analytics and customer retention 19

Increase due to a suspended plant project and reserves for obsolete inventory 13

Increase due to Stream Energy acquisition in August 2019 11

Increase primarily due to planned outages at Midwest Generation in 2020 8

Increase due to incremental safety measures resulting from COVID-19 8

Decrease in variable chemical costs due to a reduction in East generation volumes (14)

Decrease in plant deactivation costs due to projects at Midwest Generation and Encina in 2019 (12)

Decrease due to return to service costs incurred at Gregory facility in 2019 (7)

Increase due to the acquisition of Direct Energy in January 2021 $ 257

Increase in major maintenance primarily due to the duration and scope of planned and forced outages in Texas during 2021 27

Increase in variable operation and maintenance expense at the PJM coal facilities associated with increased generation in 2021 23

Increase driven by higher maintenance resulting from the impacts of Winter Storm Uri 2

Decrease driven by lower retail operations costs (29)

Decrease in lease expense primarily driven by the buyout of the Midwest Generation lease in 2020 (16)

Decrease due to the sale of fossil generating assets to Generation Bridge in December 2021

Decrease due to prior year suspended plant project and prior year reserves for obsolete inventory (9)

Increase in operations and maintenance expense $ 241

1 unchanged sentence

Other Cost of operations are comprised of the following:

(In millions) Texas East West/Other Total

(In millions) Texas East West/Services/Other Total

Year Ended December 31, 2021 $ 194 $ 129 $ 16 $ 339

2 unchanged sentences

(In millions)

Increase in gross receipts tax due to the Stream Energy acquisition in August 2019 and higher revenue from increased rates and customer counts $ 6

Decrease in ARO expense due to Encina decommissioning and Jewett Mine remediation in 2019, partially offset by an increase in costs due to changes in regulatory requirements at the Joliet facility (5)

Increase due to the acquisition of Direct Energy in January 2021 $ 83

Decrease primarily due to ARO expense in 2020 at Jewett Mine and Joliet as a result of regulatory requirements (15)

Increase in other cost of operations $ 67

1 unchanged sentence

Depreciation and amortization expenses are comprised of the following:

(In millions) Texas East West/Other Corporate Total

(In millions) Texas East West/Services/Other Corporate Total

Year Ended December 31, 2021 $ 331 $ 338 $ 88 $ 28 $ 785

Year Ended December 31, 2020 227 138 36 34 435

Depreciation and amortization expense increased by $62 million for the year ended December 31, 2020 compared to the same period in 2019, primarily due to the acquisition of Stream Energy in August 2019, retail customer book acquisitions in 2020 and the Midwest Generation lease purchase in 2020.

Depreciation and amortization expense increased by $350 million for the year ended December 31, 2021 compared to the same period in 2020, primarily due to amortization of acquired intangibles in connection with the acquisition of Direct Energy in January 2021.

Impairment Losses

During the year ended December 31, 2020, the Company recorded impairment losses of $75 million primarily related to the Cottonwood facility and the Home Solar business, compared to impairment losses of $5 million recorded on intangible assets during the same period in 2019, as further described in Item 15 — Note 11, Asset Impairments , to the Consolidated Financial Statements .

During the year ended December 31, 2021, the Company recorded impairment losses of $544 million, of which $306 million was recorded in the second quarter related to the decline in capacity prices and the planned retirement of a significant portion of the PJM coal fleet, $213 million in the fourth quarter as a result of changes in the long-term outlook of the Joliet facility prompted by market conditions and an assessment of various alternatives for the long-term operational landscape of the facility including the impact of the CEJA in Illinois, and $25 million related to various other power plants.

During the year ended December 31, 2020, the Company recorded impairment losses of $75 million primarily related to the Cottonwood facility and the Home Solar business.

Refer to Item 15 — Note 11, Asset Impairments , to the Consolidated Financial Statements for further discussion .

Selling, General and Administrative Costs

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

(In millions) Texas East West/Other Corporate Total

(In millions) Texas East West/Services/Other Corporate Total

Year Ended December 31, 2021 $ 574 $ 472 $ 198 $ 49 $ 1,293

2 unchanged sentences

(In millions)

Increase due to the acquisitions of Stream Energy in August 2019 $ 27

Increase due to income from transition services agreements ending in 2019 and an increase in personnel costs in 2020 24

Increase due to higher amortization of commissions 18

Increase in acquisition costs related to the Direct Energy acquisition 17

Increase in selling and marketing expenses primarily due to higher advertising expenses and marketing campaigns to increase customer count, partially offset by reduced spend in direct and alternative sales channels due to COVID-19 11

Increase in bad debt expense primarily due to the impact of COVID-19 5

Increase due to the acquisition of Direct Energy in January 2021 $ 460

Increase due to Winter Storm Uri, including charitable giving, legal and other costs of $20 million and ERCOT default charges of $9 million 29

Increase due to higher consulting, service and insurance costs 26

Decrease due to lower employee costs (23)

Decrease due to the favorable resolution of a legal matter (15)

Increase in selling, general and administrative costs $ 483

Reorganization Costs

For the year ended December 31, 2019, reorganization costs of $23 million primarily related to severance and contract modifications for the Transformation Plan.

The Company significantly achieved the operations and cost excellent portion of the Transformation Plan during 2019.

Equity in Earnings of Unconsolidated Affiliates

Equity in earnings of unconsolidated affiliates increased by $15 million for the year ended December 31, 2020 compared to the same period in 2019 primarily due to higher revenues at Ivanpah driven by operational efficiencies and favorable weather.

Provision for Credit Losses

Provision for credit losses are comprised of the following:

(In millions) Texas East West/Services/Other Total

Year Ended December 31, 2021 $ 678 $ 8 $ 12 $ 698

Year Ended December 31, 2020 94 14 — 108

Provision for credit losses increased by $590 million for the year ended December 31, 2021, compared to the same period in 2020, due to the following:

(In millions)

Increase due to Winter Storm Uri, including:

Increase of $403 million related to bilateral financial hedging risk

Increase of $126 million related to counterparty credit risk

Increase of $67 million related to ERCOT default shortfall payments

Decrease due to improved collections in the legacy brands, partially offset by the acquisition and integration of Direct Energy in January 2021 (6)

Increase in provision for credit losses $ 590

Acquisition-Related Transaction and Integration Costs

Acquisition-related transaction and integration costs increased by $70 million when compared to the same period in 2020.

Acquisition-related transaction costs increased by $8 million, primarily related to the Direct Energy acquisition.

Integration costs increased by $62 million, primarily related to employee costs, software costs and consulting services for the Direct Energy acquisition.

Gain on Sale of Assets

The gain on sale of assets of $247 million was recorded for the year ended December 31, 2021 includes a $210 million gain on the sale of 4,850 MW of fossil generating assets in December 2021, a $20 million gain on the sale of a deactivated site in November 2021, and a $17 million due to the sale of Agua Caliente in February 2021.

The gain on the sale of assets of $3 million for the year ended December 31, 2020 was related to the sale of land and investments in January 2020, partially offset by the disposition of the Home Solar business.

Impairment Losses on Investments

During the year ended December 31, 2020, the Company recorded other-than-temporary impairment losses on the Company's investment in Petra Nova Parish Holdings of $18 million, compared to $108 million recorded in the same period in 2019, as further described in Item 15 — Note 11, Asset Impairments , to the Consolidated Financial Statements.

Other Income, Net

Other income increased by $1 million for the year ended December 31, 2020 compared to the same period in 2019, primarily due to income from insurance proceeds received, partially offset by decreases in interest income and dividends received from cost method investments in 2020.

During the year ended December 31, 2020, the Company recorded other-than-temporary impairment losses on the Company's investment in Petra Nova Parish Holdings of $18 million, as further described in Item 15 — Note 11, Asset Impairments , to the Consolidated Financial Statements.

Loss on Debt Extinguishment

A loss on debt extinguishment of $77 million was recorded for the year ended December 31, 2021, driven by the redemption of senior notes as further discussed in Item 15 — Note 13, Long-term Debt and Finance Leases, to the Consolidated Financial Statements .

A loss on debt extinguishment of $9 million was recorded for the year ended December 31, 2020, driven by the debt extinguished in connection with the sale of Home Solar and the redemptions of the Indian River and Dunkirk bonds.

A loss on debt extinguishment of $51 million was recorded for the year ended December 31, 2019, driven by the redemption of Senior Notes, due 2024, and the repayment of the 2023 Term Loan Facility.

Interest Expense

Interest expense decreased by $12 million for the year ended December 31, 2020 compared to the same period in 2019, due to the following:

(In millions)

Decrease due to the repayment of the Term Loan and 2024 Senior Notes $ (16)

Decrease in derivative interest expense due to the termination of interest rate swaps in 2019, partially offset by settlement of in-the-money interest rate swaps in 2019 (14)

Decrease due to repayment of Agua Caliente debt in the fourth quarter of 2019 (7)

Decrease due to lower interest on the Revolving Credit Facility in 2020 (3)

Decrease due to the early settlement of an interest rate swap in 2020, partially offset by interest expense related to financings entered into in connection with the Direct Energy acquisition (2)

Increase due to full year of interest incurred in 2020 on bonds issued in the second quarter of 2019 33

Decrease in interest expense $ (12)

Income Tax Expense/(Benefit)

For the year ended December 31, 2020, NRG recorded income tax expense of $251 million on pre-tax income of $761 million.

For the same period in 2019, NRG recorded an income tax benefit of $3.3 billion on pre-tax income of $786 million.

Interest expense increased by $84 million for the year ended December 31, 2021 compared to the same period in 2020, primarily due to financings entered into in connection with the Direct Energy acquisition.

Income Tax Expense

For the year ended December 31, 2021, NRG recorded income tax expense of $672 million on pre-tax income of $2.9 billion.

For the same period in 2020, NRG recorded an income tax expense of $251 million on pre-tax income of $761 million.

The effective tax rate was 23.5% and 33.0% for the years ended December 31, 2021 and 2020, respectively.

The large benefit for the year ended December 31, 2019 was due to a $3.5 billion release of the Company’s valuation allowance.

Refer to Item 15 – Note 21, Income Taxes, to the Consolidated Financial Statements for further discussion of the release in valuation allowance.

For the year ended December 31, 2020, NRG's overall effective tax rate was different than the federal statutory tax rate of 21% primarily due to state tax expense, recognition of state valuation allowance on NOLs, and return to provision adjustments.

For the year ended December 31, 2021, NRG's overall effective tax rate was higher than the federal statutory tax rate of 21% primarily due to state tax expense partially offset by tax benefits from the revaluation of state deferred tax assets, valuation allowance, and settlements of uncertain tax positions.

Year Ended December 31,

2 unchanged sentences

Tax at federal statutory tax rate 600 160

Foreign rate differential (3) —

State taxes 111 18

4 unchanged sentences

Recognition of uncertain tax benefits (10) 3

Income tax expense/(benefit) $ 251 $ (3,334)

Income tax expense $ 672 $ 251

Effective income tax rate 23.5 % 33.0 %

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These factors and others, including the Company's history of pre-tax earnings and losses, are taken into account in assessing the ability to realize deferred tax assets.

Income from Discontinued Operations, Net of Income Tax

Year ended December 31,

(In millions) 2019

South Central $ 28

Yield Renewables Platform & Carlsbad 296

Income from discontinued operations, net of income tax $ 321

Refer to Item 15 — Note 4, Acquisitions, Discontinued Operations and Dispositions, to the Consolidated Financial Statements for further discussion.

Liquidity and Capital Resources

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As of December 31, 2021 and 2020, NRG's liquidity, excluding collateral funds deposited by counterparties, was approximately $2.7 billion and $7.0 billion, respectively, comprised of the following:

As of February 26, As of December 31,

As of December 31,

(In millions) 2021 2020

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Total 265 3,911

Total availability under Revolving Credit Facility and collective collateral facilities 1,865 3,129 1,794

Total availability under Revolving Credit Facility and collective collateral facilities (b)

Total liquidity, excluding collateral funds deposited by counterparties $ 2,686 $ 7,040

(a) Includes reserves primarily for debt service, performance obligations and capital expenditures

As of December 31, 2020, total liquidity, excluding collateral funds deposited by counterparties, increased by $4.9 billion.

The increase was primarily driven by $2.9 billion of newly-issued secured and unsecured corporate debt and a $1.5 billion increase in collateral facilities to fund the Direct Energy acquisition.

As of February 26, 2021, NRG had $3.8 billion of liquidity available to continue to support its operations.

(b) Total capacity of Revolving Credit Facility and collective collateral facilities was $5.9 billion and $4.0 billion as of December 31, 2021 and December 31, 2020, respectively

As of December 31, 2021, total liquidity, excluding collateral funds deposited by counterparties, decreased by $4.4 billion.

The decrease was primarily driven by the closing of the Direct Energy acquisition and the impact of Winter Storm Uri.

Changes in cash and cash equivalent balances are further discussed under the heading Cash Flow Discussion .

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Credit Ratings

On July 24, 2020, Moody's affirmed NRG's corporate family rating of Ba1, with positive outlook.

The agency also affirmed the ratings on all NRG's outstanding debt, including the Ba2 rating on senior unsecured bonds, Baa3 rating on senior secured bonds with fall-away security provisions and Baa2 rating on senior secured bonds without the fall-away feature.

On July 27, 2020, S&P upgraded the NRG corporate family rating to BB+ with a stable outlook and senior unsecured rating to BB+.

On March 17, 2021, following Winter Storm Uri, Standard & Poor's placed NRG's issuer credit rating of BB+ on CreditWatch with negative implications.

On May 12, 2021, Standard & Poor's affirmed NRG's issuer credit rating of BB+ with a stable outlook.

On March 19, 2021, Moody's changed NRG's rating outlook from positive to stable.

At the same time, Moody's affirmed NRG's corporate family rating of Ba1.

The following table summarizes the Company's current credit ratings:

NRG Energy, Inc.

BB+ Stable Ba1 Positive

BB+ Stable Ba1 Stable

3.75% Senior Secured Notes, due 2024 BBB- Baa3

2.00% Senior Secured Notes, due 2025 BBB- Baa3

7.25% Senior Notes, due 2026 BB+ Ba2

2.45% Senior Secured Notes, due 2027 BBB- Baa3

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3.625% Senior Notes, due 2031 BB+ Ba2

3.875% Senior Notes, due 2032 BB+ Ba2

Revolving Credit Facility, due 2024 BBB- Baa3

The principal sources of liquidity for NRG's operating and capital expenditures are expected to be derived from cash on hand, cash flows from operations and financing arrangements.

As described in Item 15 — Note 14, Long-term Debt and Finance Leases, to the Consolidated Financial Statements, the Company's financing arrangements consist mainly of the Senior Credit Facility, the Senior Notes and the Senior Secured Notes.

As described in Item 15 — Note 13, Long-term Debt and Finance Leases, to the Consolidated Financial Statements, the Company's financing arrangements consist mainly of the Senior Notes, Convertible Senior Notes, Senior Secured First Lien Notes, Revolving Credit Facility, and tax-exempt bonds.

The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following:

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(ii) debt service obligations, as described more fully in Item 15 — Note 13, Long-term Debt and Finance Leases , to the Consolidated Financial Statements;

(iii) capital expenditures, including environmental;

and (iv) allocations in connection with return of capital and dividend payments to shareholders as described in Item 15 — Note 17, Capital Structure , to the Consolidated Financial Statements, acquisition opportunities, and debt repayments.

(iii) capital expenditures, including maintenance, repowering, development, and environmental;

and (iv) allocations in connection with acquisition opportunities, debt repayments, share repurchases and dividend payments to stockholders, as described in Item 15 — Note 16, Capital Structure , to the Consolidated Financial Statements.

Direct Energy Acquisition

On July 24, 2020, the Company entered into the Purchase Agreement with Centrica plc to acquire Direct Energy, a North American subsidiary of Centrica plc.

On January 5, 2021, the Company acquired Direct Energy, which had been a North American subsidiary of Centrica.

Direct Energy is a leading retail provider of electricity, natural gas, and home and business energy related products and services in North America, with operations in all 50 U.S.

states and 8 Canadian provinces.

The acquisition increased NRG's retail portfolio by over 3 million customers and strengthens its integrated model.

It also broadens the Company's presence in the Northeast and into states and locales where it did not previously operate, supporting NRG's objective to diversify its business.

The Company paid an aggregate purchase price of $3.625 billion in cash, subject to a purchase price adjustment of $77 million.

The Company also increased its liquidity and collateral facilities by $3.4 billion through a combination of new letter of credit facilities and increases to its existing Revolving Credit Facility, as further discussed below.

Liquidity and Collateral Facility Increases

The final purchase price adjustment resulted in additional payment of $22 million, which was paid to Centrica in December 2021.

Collateral Facility Increases

The following table presents increases to the Company's liquidity and collateral facilities in connection with the Direct Energy acquisition:

(In millions) December 31, 2020

Revolving Credit Facility commitment increase (a)

Revolving Credit Facility new tranche (a)

(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

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Repurchase facility 75

Facility agreement in connection with the sale of pre-capitalized trust securities (a)

Bilateral letter of credit facilities 475

Total Increases to Liquidity and Collateral Facilities $ 3,399

(a) Available upon the Acquisition Closing Date

In connection with the close of the Direct Energy acquisition, the Company is working to replace the collateral posted by Centrica plc utilizing the availability under the above and existing facilities.

Issuance of 2029 Senior Unsecured Notes and 2031 Senior Unsecured Notes

On December 2, 2020, NRG issued $500 million aggregate principal amount of 3.375% senior notes due 2029 (the “2029 Unsecured Notes”) and $1.0 billion aggregate principal amount of 3.625% senior notes due 2031 (the “2031 Unsecured Notes” and, together with the 2029 Unsecured Notes, the “Unsecured Notes”).

Interest is payable on the Unsecured Notes on February 15 and August 15 of each year beginning on August 15, 2021 until the maturity date of February 15, 2029 for the 2029 Unsecured Notes and February 15, 2031 for the 2031 Unsecured Notes.

Issuance of 2025 and 2027 Senior Secured First Lien Notes

On December 2, 2020, NRG issued $1.4 billion of aggregate principal amount of senior secured first lien notes, consisting of $500 million 2.000% senior secured first lien notes due 2025 (the “2025 Secured Notes”) and $900 million 2.450% senior secured first lien notes due 2027 (the “2027 Secured Notes” and, together with the 2025 Secured Notes, the “2025 and 2027 Senior Secured First Lien Notes”), at a discount.

The 2027 Secured Notes were issued under NRG’s Sustainability-Linked Bond Framework, which sets out certain sustainability targets, including reducing greenhouse gas emissions.

Failure to meet such sustainability targets will result in a 25 basis point increase to the interest rate payable on the 2027 Secured Notes from and including the interest period ending on June 2, 2026.

The 2025 and 2027 Senior Secured First Lien Notes are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement.

The 2025 and 2027 Senior Secured First Lien Notes will be secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors.

The collateral securing the 2025 and 2027 Senior Secured First Lien Notes will be released if the Company obtains an investment grade rating from two out of the three rating agencies, subject to an obligation to reinstate the collateral if such rating agencies withdraw the Company's investment grade rating or downgrade its rating below investment grade Interest is payable on the 2025 and 2027 Senior Secured First Lien Notes on June 2 and December 2 of each year beginning on June 2, 2021 until the maturity date of December 2, 2025 for the 2025 Secured Notes and until the maturity date of December 2, 2027 for the 2027 Secured Notes.

Dunkirk Bonds

On March 11, 2020, NRG issued $59 million in aggregate principal amount of NRG Dunkirk 2020 1.30% tax-exempt refinancing bonds due 2042 (the "Dunkirk Bonds").

The Dunkirk Bonds are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement.

The Dunkirk Bonds are secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors.

The collateral securing the Dunkirk Bonds will, at the request of NRG, be released if NRG satisfies certain conditions, including receipt of an investment grade rating on its senior, unsecured debt securities from two out of the three rating agencies, subject to reversion if those rating agencies withdraw their investment grade rating of the Bonds or any of NRG’s senior, unsecured debt securities or downgrade such rating below investment grade.

The Dunkirk Bonds are subject to mandatory tender and purchase on April 3, 2023 and have a final maturity date of April 1, 2042.

NRG used the net proceeds from the offering to redeem in 2020 the existing principal amount of outstanding Dunkirk Power LLC 5.875% tax exempt bonds due 2042.

Indian River Bonds

On December 17, 2020, NRG issued $57 million in aggregate principal amount of NRG Indian River 2020 1.25% tax-exempt refinancing bonds due 2040 (the "IR 2040 Bonds") and $190 million aggregate principal amount of NRG Indian River Power 2020 1.25% tax-exempt refinancing bonds due 2045 (the "IR 2045 Bonds") (together the "IR Bonds").

The IR Bonds are guaranteed on a first-priority basis by each of NRG’s current and future subsidiaries that guarantee indebtedness under its credit agreement.

The Bonds are secured by a first priority security interest in the same collateral that is pledged for the benefit of the lenders under NRG’s credit agreement, which consists of a substantial portion of the property and assets owned by NRG and the guarantors.

The collateral securing the IR Bonds will, at the request of NRG, be released if NRG satisfies certain conditions, including receipt of an investment grade rating on its senior, unsecured debt securities from two out of the three rating agencies, subject to reversion if those rating agencies withdraw their investment grade rating of the IR Bonds or any of NRG’s senior, unsecured debt securities or downgrade such rating below investment grade.

The IR Bonds are subject to mandatory tender and purchase on October 1, 2025 and have final maturity dates of October 1, 2040 for the IR 2040 Bonds and October 1, 2045 for the IR 2045 Bonds.

NRG used the net proceeds from the offering to redeem in 2020 the existing principal amounts of outstanding Indian River Power 6.000% tax exempt bonds due 2040 and Indian River Power LLC 5.375% tax exempt bonds due 2045.

Revolving Credit Facility

The Company had $83 million outstanding under its Revolving Credit Facility as of December 31, 2019, which was used to repay the outstanding indebtedness on the Agua Caliente Borrower 1 notes on a leverage-neutral basis during the fourth quarter of 2019.

There were no borrowings outstanding as of December 31, 2020.

On August 20, 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, (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 "Acquisition Closing Date"), The maturity date of the new revolving tranche of commitments may, upon request by the Company, 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 loan made pursuant thereto are identical.

The increase in the existing commitments and the commitments with respect to the new tranche are effective on August 20, 2020 but only became available on the Acquisition Closing Date.

For further discussion on the acquisition of Direct Energy see Item 15 — Note 4, Acquisitions, Discontinued Operations and Dispositions , to the Consolidated Financial Statements.

Upon the Acquisition Closing Date, total revolving commitments available, subject to usage, under this amendment will be $3.7 billion.

In addition, the amendment includes changes to, among other things, (i) permit the borrowing of up to the full amount of the revolving commitments in Canadian dollars, (ii) increase the swingline facility from $50 million to $100 million and provide a $10 million swingline facility in Canadian dollars, (iii) increase the credit facilities lien basket from the greater of $6 billion and 30% of total assets to the greater of $10 billion and 30% of total assets, (iv) increase the credit facilities debt basket from $6 billion to $10 billion, (v) increase the basket for securitization indebtedness from $750 million to $1.7 billion, (vi) provide an additional indebtedness basket equal to $600 million for certain liquidity facilities, and (vii) make certain other changes to the existing covenants and other provisions.

Put Option Agreement for Senior Debt Issuance

During the fourth quarter of 2020, the Company entered into a 3-year put option agreement with a Delaware trust formed by the Company upon completion of the sale of $900 million pre-capitalized trust securities redeemable November 15, 2023 (the “P-Caps”).

The Trust invested the proceeds from the sale of the P-Caps in a portfolio of principal and interest strips of U.S.

Treasury securities (the “Eligible Treasury Assets”).

Under the put option agreement, NRG has the right, from time to time, to issue to the Trust and to require the Trust to purchase from NRG, on one or more occasions (the “Issuance Right”), up to $900 million aggregate principal amount of NRG’s 1.841% Senior Secured First Lien Notes due 2023 (the “P-Caps Secured Notes”) in exchange for all or a portion of the Eligible Treasury Assets corresponding to the portion of the Issuance Right.

NRG will pay a semi-annual premium to the Trust at a rate of 1.65%.

In connection with the issuance of the P-Caps, on December 2, 2020, NRG entered into a facility agreement for the issuance of letters of credit (the “LC Agreement”) and Deutsche Bank Trust Company Americas as collateral agent (the “Collateral Agent”) and administrative agent pursuant to which certain financial institutions (the “LC Issuers”) are permitted to join with commitments 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 currently outstanding letters of credit and other credit support issued for the account of entities being acquired pursuant to the Acquisition.

In addition, on December 2, 2020, the Trust entered into a 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”).

As of December 31, 2020 no letters of credit were issued under this agreement .

See Note 14, Long-term Debt and Finance Leases for further discussion.

Credit Default Swap Facility

On January 4, 2019, the Company entered into an $80 million credit agreement to issue letters of credit, which is currently supporting the Cottonwood facility lease.

Annual fees of 1.33% on the facility were paid quarterly in advance.

On August 13, 2020, the agreement was amended permitting the Company to increase the size of the facility and fees on the facility were adjusted to reflect the costs of the credit default swaps that serve as collateral for the facility.

In order to increase the Company’s collective collateral facilities in connection with the Direct Energy acquisition.

NRG expanded the facility allowing for the issuance of an additional $150 million of letters of credit as of December 31, 2020.

As of December 31, 2020, $229 million was issued under this facility.

Bilateral Letter of Credit Facilities

In December 2020, the Company entered into a series of bilateral letter of credit facilities to allow for the issuance of up to $475 million of letters of credit.

These facilities are uncommitted.

As of December 31, 2020, $5 million was issued under these facilities.

Receivables Securitization

On September 22, 2020, NRG Receivables LLC, a bankruptcy remote, special purpose, indirect wholly owned subsidiary, entered into the Receivables Facility for an amount up to $750 million, subject to adjustments on a seasonal basis, with issuers of asset-backed commercial paper and commercial banks (the "Lenders".) The assets of NRG Receivables LLC are first available to satisfy the claims of the Lenders before making payments on the subordinated note and equity issued by NRG Receivables LLC.

The assets of NRG Receivables LLC are not available to the Company and its subsidiaries and creditors unless and until distributed by NRG Receivables LLC.

Under the Receivables Facility, certain indirect subsidiaries of the Company sell their accounts receivables to NRG Receivables LLC, subject to certain terms and conditions.

In turn, NRG Receivables LLC has granted a security interest in the purchased receivables to the Lenders as collateral for borrowings of cash and issuances of letters of credit.

Receivables remain on the Company's consolidated balance sheet and amounts funded by the Lenders to NRG Receivables LLC are reflected as short-term borrowings.

Cash flows from the Receivables Facility are reflected as financing activities in the Company's Consolidated Statements of Cash Flows.

The Company will continue to service the receivables sold in exchange for a servicing fee.

The Receivables Facility is scheduled to expire on September 21, 2021, unless renewed by the mutual consent of the parties in accordance with its terms.

Borrowings by NRG Receivables LLC under the Receivables Facility bear interest as defined under the Receivables Financing Agreement.

The weighted average interest rate related to usage under the Receivables Facility as of December 31, 2020 was 0.537%.

Planned Debt Reduction

In light of the impact of Winter Storm Uri, the Company's deleveraging program will extend to 2023.

The Company remains committed to maintaining a strong balance sheet and continues to work to achieve investment grade credit metrics.

Issuance of 2032 Senior Notes

On August 23, 2021, the Company issued $1.1 billion of aggregate principal amount at par of 3.875% senior notes due 2032 (the "2032 Senior Notes").

The 2032 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries.

The 2032 Senior Notes were issued under NRG's Sustainability-Linked Bond Framework, which sets out certain sustainability targets, including reducing greenhouse gas emissions.

Failure to meet such sustainability targets will result in a 25 basis point increase to the interest rate payable on the 2032 Senior Notes from and including August 15, 2026.

Senior Note Redemptions

During the year ended December 31, 2021, the Company redeemed $1.9 billion in aggregate principal of its Senior Notes for $1.9 billion using the proceeds of the 2032 Senior Notes and cash on hand.

In connection with the redemptions, a $77 million loss on debt extinguishment was recorded.

Receivables Facility

On July 26, 2021, NRG Receivables LLC, a wholly-owned indirect subsidiary of the Company, renewed its existing accounts receivable securitized borrowings facility (the "Receivables Facility") to, among others, (i) increase the facility size to $800 million, (ii) extend the maturity date until July 26, 2022, (iii) make certain adjustments to the pool of receivables through the Receivables Facility and certain related covenants, and (iv) provide for revised language relating to interest determination based on SOFR in case of a LIBOR cessation or the occurrence of certain other trigger events.

As of December 31, 2021, there were no outstanding borrowings and there were $400 million in letters of credit issued under the Receivables Facility.

Repurchase Facility

On September 22, 2020, the Company entered into an uncommitted repurchase facility (“Repurchase Facility”) related to the Receivables Facility.

Under the Repurchase Facility the Company can borrow up to $75 million, collateralized by a subordinated note issued by NRG Receivables LLC to NRG Retail LLC in favor of the originating entities representing a portion of the balance of receivables sold to NRG Receivables LLC under the Receivables Facility.

The Repurchase Facility is scheduled to expire on September 22, 2021, unless renewed by the mutual consent of the parties in accordance with its terms.

The Repurchase Facility has no commitment fee and borrowings will be drawn at LIBOR +1.25%.

On July 26, 2021, the Company renewed its existing uncommitted repurchase facility ("Repurchase Facility") to, among other things, (i) extend the maturity date to July 26, 2022 and (ii) provide for revised language relating to interest determination based on SOFR in case of a LIBOR cessation or the occurrence of certain other trigger events.

On February 9, 2022, the Company entered into amendments to its existing Repurchase Facility to, among other things, (i) increase the size of the facility from $75 million to $150 million and (ii) replace LIBOR with term SOFR as the benchmark for the pricing rate.

The Repurchase Facility has no commitment fee and borrowings will be drawn at SOFR + 1.30%.

As of December 31, 2021, there were no outstanding borrowings under the Repurchase Facility.

Midwest Generation Lease Purchase

The Company funded the purchase with cash-on-hand.

Upon closing, lease expense related to these facilities, which totaled approximately $14 million in 2019, and the operating lease liability of $148 million were eliminated.

Sale of Agua Caliente

On November 19, 2020, the Company entered into an agreement to sell its 35% ownership in Agua Caliente to Clearway Energy for $202 million.

The sale of the solar project closed on February 3, 2021.

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

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.

On December 1, 2021, the Company closed the previously announced sale of approximately 4,850 MWs of fossil generating assets from its East and West regions to Generation Bridge, an affiliate of ArcLight Capital Partners.

At Closing, NRG received $623 million of net proceeds, after working capital and other adjustments, including a deduction for cash flows generated of approximately $11 million per month from the beginning of the year until the closing of the transaction, in lieu of

cash flows generated during the year.

As part of the transaction, NRG entered into a tolling agreement for the 866 MW Arthur Kill plant in New York City through April 2025.

Sale of Agua Caliente

On February 3, 2021, the Company closed on the sale of its 35% ownership in the Agua Caliente solar project to Clearway Energy, Inc.

for $202 million.

NRG recognized a gain on the sale of $17 million, including cash disposed of $7 million.

On March 27, 2020, the U.S.

government enacted the CARES Act, which provides, among other things, the option to defer payments of certain 2019 employer payroll taxes incurred after the date of enactment and pension contributions due in 2020, as well as claim a refund now for AMT credits from the IRS that were previously refundable over several years.

As a result, the Company (i) deferred the payment of $17 million for the employer share of 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 and (ii) 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, $22 million was paid to GenOn for its share of the AMT credits received during the year of 2020.

government enacted the CARES Act, which provides, among other things:

(i) the option to defer payments of certain 2019 employer payroll taxes incurred after the date of enactment;

and (ii) allows NOLs from tax years 2018, 2019, and 2020 to be carried back five years.

The total benefit to the Company due to the CARES Act was $35 million.

Of this amount, $13 million was paid to social security in 2021 and $13 million will be payable in 2022.

Pension Plan Contribution

In the Company's 2019 Form 10-K, NRG had anticipated making contributions of $63 million to its pension plans, including STP, in 2020.

Cash contributions of $18 million were made during 2020, of which $7 million was related to STP.

The remaining planned contributions for 2020 were satisfied by available pre-funded pension balances (previous contributions in excess of required pension contributions).

The American Rescue Plan Act ("ARPA") was enacted on March 11, 2021 to provide economic relief related to the COVID-19 pandemic.

ARPA provided pension funding relief for single employer plans, among other provisions.

As a result, NRG reduced its 2021 planned cash contribution by approximately $23 million.

Pension and Other postretirement benefits minimum funding requirements

As of December 31, 2021, the Company does not have estimated minimum pension contributions required under the Pension Protection Act of 2006 for the next 5 years.

As of December 31, 2021, the Company’s estimated Other postretirement benefits minimum funding requirements for the next 5 years were $33 million, of which $7 million are required to be made within the next 12 months.

These amounts represent estimates based on assumptions that are subject to change.

For further discussion, see Item 15 — Note 15, Benefit Plans and Other Postretirement Benefits , to the Consolidated Financial Statements.

Debt Service Obligations

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Total Debt and Finance Leases $ 4 $ 3 $ 603 $ 502 $ — $ 7,001 $ 8,113

The Company plans to reduce debt by nearly $1.2 billion during 2021 to maintain its targeted investment grade credit metrics.

The Company intends to fund the repurchase from cash from operations.

NRG continues to look at optimizing its debt structure and seeking out lower interest rates.

Interest Payments $ 385 $ 383 $ 363 $ 352 $ 334 $ 1,224 $ 3,041

For further discussion, see Item 15 — Note 13, Long-term Debt and Finance Leases .

Market Operations

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buying fuel before receiving energy revenues);

(iv) initial collateral for large structured transactions;

and (v) collateral for project development.

As of December 31, 2020, market operations had total cash collateral outstanding of $50 million and $768 million outstanding in letters of credit to third parties primarily to support its market activities for both wholesale and retail transactions.

As of December 31, 2020, total funds deposited by counterparties was $19 million in cash and $75 million of letters of credit.

Future liquidity requirements, including those related to the acquisition of Direct Energy, may change based on the Company's hedging activities and structures, power purchases and sales, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility.

and (iv) initial collateral for large structured transactions.

As of December 31, 2021, market operations had total cash collateral outstanding of $291 million and $3.5 billion outstanding in letters of credit to third parties primarily to support its market activities.

As of December 31, 2021, total funds deposited by counterparties were $845 million in cash and $429 million of letters of credit.

The Company has entered into long-term contractual arrangements to procure certain fuel and transportation services for the Company's generation assets.

As of December 31, 2021, the Company had minimum payment obligations under such outstanding agreements of $378 million, with $122 million payable within the next 12 months.

Additionally, the Company has long-term contractual commitments related to electricity and natural gas products, including power purchases, gas transportation and storage of various quantities and durations, and renewable purchased power agreements under PPAs with third-party project developers, which are accounted for as NPNS.

As of December 31, 2021, the Company had minimum purchased energy commitments of $5.0 billion, with $1.6 billion payable within the next 12 months.

For further discussion, see Item 15 — Note 23, Commitments and Contingencies .

Future liquidity requirements may change based on the Company's hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility.

In addition, liquidity requirements are dependent on the Company's credit ratings and general perception of its creditworthiness.

First Lien Structure

NRG has granted first liens to certain counterparties on a substantial portion of 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 hedge agreements for forward sales of power or gas used as a proxy for power.

To the extent that the underlying hedge positions for a counterparty are out-of-the-money to NRG, the counterparty would have a claim under the first lien program.

The first lien program limits the volume that can be hedged, not the value of underlying out-of-the-money positions.

The first lien program does not require NRG to post collateral above any threshold amount of exposure.

Within the first lien structure, the Company can hedge up to 80% of its coal and nuclear capacity and 10% of its other assets with these counterparties for the first 60 months and then declining thereafter.

Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty.

NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, subject to various exclusions including NRG's assets that have project-level financing and the assets of certain non-guarantor subsidiaries, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents.

The first lien program does not limit the volume that can be hedged or the value of underlying out-of-the-money positions.

The first lien program also does not require NRG to post collateral above any threshold amount of exposure.

The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.

The Company's first lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices.

As of December 31, 2020, all hedges under the first liens were in-the-money on a counterparty aggregate basis.

As of December 31, 2021, all hedges under the first liens were out-of-the-money on a counterparty aggregate basis.

The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of December 31, 2021:

Equivalent Net Sales Secured by First Lien Structure (a)

2021 2022 2023 2024

In MW 653 738

As a percentage of total net coal and nuclear capacity (b)

15% 18% 18% —%

(a) Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region

(b) Net coal and nuclear capacity represents 80% of the Company's total coal and nuclear assets eligible under the first lien, which excludes coal assets acquired in the Midwest Generation acquisition

Small Book Acquisitions

During 2020, the Company acquired multiple books of customers totaling approximately 56,000 customers for $22 million.

Capital Expenditures

3 unchanged sentences

East (23) (1) (26) (50)

West/Other (30) — — (30)

West/Services/Other (21) — — (21)

Corporate (4) — (41) (45)

Total capital expenditures (156) (3) (71) (230)

Other investments — — (32) (32)

Total cash capital expenditures for 2021

(175) (2) (92) (269)

Investments — — (47) (47)

Total capital expenditures and investments $ (175) $ (2) $ (139) $ (316)

(a) Includes other investments, acquisitions, digital NRG and costs to achieve.

Excludes Midwest Generation lease buyout

(a) Includes other investments, acquisitions, digital NRG and integration projects

Growth investments in East for the year ended December 31, 2021 include the Astoria generating facility, for which the Company has proposed to replace existing units with a single, new state-of-the-art Simple Cycle Combustion Turbine having a total generating capacity of 437 MW.

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 other investments are expenditures for Encina site improvements classified as ARO payments.

Demolition at the Encina site is underway and is expected to be completed in the first half of 2022.

The Company expects to initiate the planning and marketing process of the Encina site in 2021.

On October 27, 2021, the NYSDEC Staff denied the Company's application for an air permit.

On November 26, 2021, Astoria Gas Turbine Power LLC filed a Request for Adjudicatory Hearing on the NYSDEC's denial.

To date, the Company has spent approximately $42 million on the Astoria project.

Additionally, included in Investments are expenditures for Encina site improvements classified as ARO payments.

Demolition of Encina is underway and is expected to be completed in the first half of 2022.

The Company expects to begin marketing the site in 2022.

Environmental Capital Expenditures Estimate

NRG estimates that environmental capital expenditures from 2022 through 2026 required to comply with environmental laws will be approximately $56 million.

These costs are primarily associated with the cost of complying with the federal CCR rule and ash storage projects.

The largest component is the cost of complying with ELG at our coal units in Texas.

The table below summarizes the status of NRG's coal fleet with respect to air quality controls.

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SNCR - Selective Non-Catalytic Reduction

The following table summarizes the estimated environmental capital expenditures by region:

(In millions) Texas East Total

2021 $ 2 $ 7 $ 9

2022 10 17 27

Total $ 22 $ 39 $ 61

The following table summarizes the estimated environmental capital expenditures by year:

(In millions) Total

Share Repurchases

Common Stock Dividends

NRG increased the annual dividend to $1.20 per share from $0.12 per share in the first quarter of 2020, and to $1.30 per share beginning in the first quarter of 2021.

NRG expects to target an annual dividend growth rate of 7-9% per share in subsequent years.

In December 2021, the Company's board of directors authorized the Company to repurchase $1.0 billion of its common stock.

See Item 15 - Note 16, Capital Structure , to the Consolidated Financial Statements for additional discussion.

Dividend Increase

In the first quarter of 2021, NRG increased the annual dividend to $1.30 from $1.20 per share.

The Company returned $320 million of capital to shareholders in the year ended 2021 through a $1.30 dividend per common share.

In 2022, NRG further increased the annual dividend to $1.40 per share, representing an 8% increase from 2021.

The Company expects to target an annual dividend growth rate of 7-9% per share in subsequent years.

On January 21, 2022, NRG declared a quarterly dividend on the Company's common stock of $0.35 per share, or $1.40 per share on an annualized basis, payable on February 15, 2022, to stockholders of record as of February 1, 2022.

The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws and regulations.

Additional Material Cash Requirements Not Discussed Above

Operating leases — The Company leases generating facilities, land, office and equipment, railcars, fleet vehicles and storefront space at retail stores.

As of December 31, 2021, the Company had lease payment obligations of $372 million, of which $96 million is payable within the next 12 months.

For further discussion, see Item 15 — Note 10, Leases.

Other liabilities — Other liabilities includes water right agreements, service and maintenance agreements, stadium naming rights, stadium sponsorships, LTSA commitments and other contractual obligations.

As of December 31, 2021, the Company had total of $210 million under such commitments, of which $41 million are payable within the next 12 months.

Contingent obligations for guarantees — NRG and its subsidiaries enter into various contracts that include indemnifications and guarantee provisions as a routine part of the Company’s business activities.

For further discussion, see Item 15 —Note 27, Guarantees.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in Equity investments — As of December 31, 2021, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting.

Ivanpah is considered a variable interest entity for which NRG is not the primary beneficiary.

NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $535 million as of December 31, 2021.

This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG.

See also Item 15 — Note 17, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Consolidated Financial Statements for additional discussion.

Cash Flow Discussion

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Net cash provided by operating activities $ 493 $ 1,837 $ (1,344)

Net cash (used)/provided by investing activities (494) 556 (1,050)

Net cash provided/(used) by financing activities 2,204 (2,148) 4,352

Net Cash Provided/(Used) By Operating Activities

Changes to net cash provided/(used) by operating activities were driven by:

Net cash used by investing activities (3,039) (494) (2,545)

Net cash (used)/provided by financing activities (272) 2,204 (2,476)

Net Cash (Used)/Provided By Operating Activities

Changes to net cash (used)/provided by operating activities were driven by:

(In millions)

Increase in operating income adjusted for other non-cash items $ 212

Increase in working capital primarily attributed to lower fuel payables in 2020 driven by lower volumes of gas and fewer coal shipments received.

Increase in other working capital due to the final settlement of the asbestos liability with ComEd and the resulting reduction of the accrual in 2019 53

Increase primarily due to decreased pension contributions in 2020 due to the utilization of pre-funded pension balances 50

Decrease due to receipt of refundable AMT credits (34)

Decrease in working capital related to accounts receivable primarily driven by milder weather in 2020, the impact of Winter Storm Uri and additional early settlement of capacity obligations in 2021 $ (1,232)

Decrease in operating income adjusted for other non-cash items (1,235)

Changes in cash collateral in support of risk management activities due to change in commodity prices 670

Change in cash provided by discontinued operations (8)

Increase in working capital related to accounts payable primarily driven by increases in gas purchases and bilateral physical settlements driven by price and volume in ERCOT 532

Decrease in working capital related to inventory due to replenishing natural gas inventory at significantly higher prices (88)

Other changes in working capital 9

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(In millions)

Decrease in proceeds from sales of assets and discontinued operations primarily due to sales of South Central and Carlsbad in 2019 $ (1,213)

Change in investments in unconsolidated affiliates 93

Decrease in cash paid for acquisitions of assets, businesses and leases 71

Decrease in contributions to discontinued operations 44

Decrease in net sales of emissions allowances (21)

Increase in purchases of investments in nuclear decommissioning trust fund securities, net of proceeds from sales (18)

Net Cash Provided/(Used) By Financing Activities

Changes in net cash provided/(used) by financing activities were driven by:

Increase in cash paid for acquisitions of assets primarily for Direct Energy $ (3,275)

Increase in proceeds from sale of assets primarily due to the fossil generating assets and Agua Caliente 749

Decrease in capital expenditures (39)

Increase in proceeds from sales of investments in nuclear decommissioning trust fund securities, net of purchases 12

Increase in sales of emissions allowances, net of purchases 10

Net Cash (Used)/Provided By Financing Activities

Changes in net cash (used)/provided by financing activities were driven by:

(In millions)

Decrease in payments of long-term debt $ 2,236

Increase in proceeds from issuance of long-term debt 1,401

Decrease in proceeds from issuance of long-term debt $ (2,134)

Increase in payments of long-term debt (1,526)

Increase in net receipts from settlement of acquired derivatives 945

Decrease in payments for share repurchase activity 181

Increase in proceeds from Revolving Credit Facility and Receivables Securitization Facilities 83

Increase in payments of dividends to common stockholders (24)

Changes in the Revolving Credit Facility (166)

Change in cash provided by discontinued operations (43)

Increase in payments of debt extinguishment costs and deferred issuance costs (19)

NOLs, Deferred Tax Assets and Uncertain Tax Position Implications

As of December 31, 2020, the Company had domestic pre-tax book income of $749 million and foreign pre-tax book income of $12 million.

For the year ended December 31, 2021, the Company had domestic pre-tax book income of $2.8 billion and foreign pre-tax book income of $100 million.

For the year ended December 31, 2021, the Company utilized U.S.

federal NOLs of $134 million due to current year taxable income.

federal NOLs of $1.6 billion due to current year taxable income.

As of December 31, 2021, the Company has cumulative U.S.

federal NOL carryforwards of $10.1 billion, which will begin expiring in 2031 and cumulative state NOL carryforwards of $5.4 billion.

federal NOL carryforwards of $8.4 billion, of which $11 million were generated prior to Tax Cuts and Jobs Act and will begin expiring in 2031 and cumulative state NOL carryforwards of $5.2 billion for financial statement purposes.

NRG also has cumulative foreign NOL carryforwards of $383 million, which do not have an expiration date.

In addition to the above NOLs, NRG has a $20 million indefinite carryforward for interest deductions, as well as $384 million of tax credits to be utilized in future years.

As a result of the Company's tax position, including the utilization of federal and state NOLs, and based on current forecasts, the Company anticipates income tax payments, primarily due to state and local jurisdictions, of up to $26 million in 2021.

The Company has $15 million of tax effected uncertain state tax benefits for which the Company has recorded a non-current tax liability of $18 million (including accrued interest) until such final resolution with the related taxing authority.

As a result of the Company's tax position, including the utilization of federal and state NOLs, and based on current forecasts, the Company anticipates income tax payments, due to federal, state and foreign jurisdictions, of up to $58 million in 2022.

The Company has $13 million of tax effected uncertain federal and state tax benefits for which the Company has recorded a non-current tax liability of $14 million (including accrued interest) until such final resolution with the related taxing authority.

The Company is no longer subject to U.S.

federal income tax examinations for years prior to 2018.

With few exceptions, state and local income tax examinations are no longer open for years before 2012.

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.

See also Item 15 — Note 28, Guarantees, to the Consolidated Financial Statements for additional discussion.

Retained or Contingent Interests

NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in Equity investments — As of December 31, 2020, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting.

Ivanpah is considered a variable interest entity for which NRG is not the primary beneficiary.

NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $829 million as of December 31, 2020.

This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG.

See also Item 15 — Note 18, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Consolidated Financial Statements for additional discussion.

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.

The following tables summarize NRG's contractual obligations and contingent obligations for guarantees.

See also Item 15 — Note 14, Long-term Debt and Finance Leases , Note 24, Commitments and Contingencies , and Note 28, Guarantees , to the Consolidated Financial Statements for additional discussion.

By Remaining Maturity at December 31,

(In millions) 2020

Contractual Cash Obligations Under

1-3 Years 3-5 Years Over

Long-term debt (including estimated interest)

$ 431 $ 901 $ 1,883 $ 9,098 $ 12,313

Finance lease obligations (including estimated interest)

Operating leases 86 163 118 34 401

Fuel purchase and transportation obligations

146 167 132 80 525

Purchased power commitments (b)

48 112 99 316 575

Pension minimum funding requirement (c)

27 30 25 43 125

Other postretirement benefits minimum funding requirement (d)

6 11 10 19 46

Other liabilities (e)

34 46 34 108 222

Cash consideration for the acquisition of Direct Energy (f)

3,702 — — — 3,702

Total $ 4,481 $ 1,433 $ 2,301 $ 9,698 $ 17,913

(a) Excludes $15 million non-current payable relating to NRG's uncertain tax benefits under ASC 740 as the period of payment cannot be reasonably estimated.

Also excludes $760 million of asset retirement obligations that are discussed in Item 15 — Note 15, Asset Retirement Obligations , to the Consolidated Financial Statements

(b) Includes purchase power commitments and renewable minimum purchase power commitments under PPAs

(c) These amounts represent the Company's estimated minimum pension contributions required under the Pension Protection Act of 2006.

These amounts represent estimates based on assumptions that are subject to change.

(d) These amounts represent estimates based on assumptions that are subject to change

(e) Includes water right agreements, service and maintenance agreements, stadium naming rights, stadium sponsorships, LTSA commitments and other contractual obligations

(f) On January 5, 2021 the Company acquired all of the issued and outstanding common shares of Direct Energy and paid an aggregate purchase price of $3.625 billion in cash, subject to a purchase price adjustment of $77 million.

For more information see Item 15 — Note 4, Acquisitions, Discontinued Operations and Dispositions .

By Remaining Maturity at December 31,

(In millions) 2020

Guarantees Under

1-3 Years 3-5 Years Over

Letters of credit and surety bonds $ 1,049 $ 73 $ 31 $ — $ 1,153

Asset sales guarantee obligations 86 282 26 112 506

Other guarantees — — — 87 87

Total guarantees $ 1,135 $ 355 $ 57 $ 199 $ 1,746

With few exceptions, state and Canadian income tax examinations are no longer open for years before 2013.

Guarantor Financial Information

As of December 31, 2020, the Company had outstanding $5.9 billion of Senior Notes and Convertible Senior Notes due 2026 to 2048 and outstanding $2.5 billion of Senior Secured First Lien Notes due from 2024 to 2029, as shown in Note 14, Long-term Debt and Finance Leases .

These Senior Notes and Senior Secured First Lien Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries (the “Guarantors”).

As of December 31, 2021, the Company's outstanding registered senior notes consisted of $375 million of the 2027 Senior Notes and $821 million of the 2028 Senior Notes, as shown in Note 13, Long-term Debt and Finance Leases .

These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries (the “Guarantors”).

See Exhibit 22.1 for a listing of the Guarantors.

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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”).

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.

In March 2020, the SEC adopted final rules that amend the financial disclosure requirements for subsidiary issuers and guarantees of registered debt securities under Rule 3-10 of Regulation S-X, permitting registrants to disclose summarized financial information for each subsidiary issuer and guarantor.

These final rules were codified in Rule 13-01 of Regulation S-X.

In compliance thereof, the Company is including summarized financial information for NRG Energy, Inc.

and the Guarantors on a combined basis after transactions and balances within the combined entities have been eliminated.

The tables below present summarized financial information of NRG Energy, Inc.

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Total other expense (467)

Income from Continuing Operations 663

Income from continuing operations before income taxes 3,286

Net Income 2,633

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NRG may enter into power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at power plants or retail load obligations.

In addition, in order to mitigate foreign exchange rate risk primarily associated with the purchase of USD denominated natural gas for the Company's Canadian business, NRG enters into foreign exchange contract agreements.

NRG's trading activities are subject to limits in accordance with the Company's Risk Management Policy.

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For a full discussion of the Company's valuation methodology of its contracts, see Derivative Fair Value Measurements in Item 15 — Note 5, Fair Value of Financial Instruments , to the Consolidated Financial Statements.

Derivative Activity Gains/(Losses) (In millions)

Derivative Activity (Losses)/Gains (In millions)

Fair value of contracts as of December 31, 2020 $ (63)

Contracts realized or otherwise settled during the period 190

Contracts acquired from Direct Energy (283)

Changes in fair value 2,497

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(In millions) Maturity

Fair value hierarchy (Losses)/Gains 1 Year or Less Greater Than 1 Year to 3 Years Greater Than 3 Years to 5 Years Greater Than

Fair value hierarchy Gains 1 Year or Less Greater Than 1 Year to 3 Years Greater Than 3 Years to 5 Years Greater Than

Level 1 $ 134 $ 192 $ 23 $ 6 $ 355

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As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative assets and liability position is a better indicator of NRG's hedging activity.

As of December 31, 2020, NRG's net derivative liability was $63 million, a decrease to total fair value of $130 million as compared to December 31, 2019.

This decrease was primarily driven by roll-off trades that settled during the period, as well as losses in fair value.

Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in an increase of approximately $102 million in the net value of derivatives as of December 31, 2020.

The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of the derivative contracts would result in a decrease of approximately $105 million in the net value of derivatives as of December 31, 2020.

Critical Accounting Policies and Estimates

NRG's discussion and analysis of the financial condition and results of operations are based upon the Consolidated Financial Statements, which have been prepared in accordance with GAAP.

As of December 31, 2021, NRG's net derivative asset was $2.3 billion, an increase to total fair value of $2.4 billion as compared to December 31, 2020.

This increase was primarily driven by roll-off trades that settled during the period, as well as gains in fair value.

Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in an increase of approximately $1.3 billion in the net value of derivatives as of December 31, 2021.

The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of the derivative contracts would result in a decrease of approximately $1.4 billion in the net value of derivatives as of December 31, 2021.

Critical Accounting Estimates

The Company's discussion and analysis of the financial condition and results of operations are based upon the Consolidated Financial Statements, which have been prepared in accordance with GAAP.

The preparation of these financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities.

The application of 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.

The application of appropriate technical accounting rules and guidance involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and the fair value of certain assets and liabilities.

These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use.

In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies have not changed.

On an ongoing basis, NRG evaluates these estimates, utilizing historic experience, consultation with experts and other methods the Company considers reasonable.

NRG evaluates these estimates, on an ongoing basis, utilizing historic experience, consultation with experts and other methods the Company considers reasonable.

In any event, actual results may differ substantially from the Company's estimates.

Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the information that gives rise to the revision becomes known.

NRG's significant accounting policies are summarized in Item 15 — Note 2, Summary of Significant Accounting Policies , to the Consolidated Financial Statements.

The Company identifies its most critical accounting policies as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain.

Accounting Policy Judgments/Uncertainties Affecting Application

The Company identifies its most critical accounting estimates as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and require the most difficult, subjective, and/or complex judgments by management about matters that are inherently uncertain.

Such accounting estimates include:

Accounting Estimate Judgments/Uncertainties Affecting Application

Derivative Instruments Assumptions used in valuation techniques

Assumptions used in forecasting generation

Assumptions used in forecasting borrowings

Assumptions used in forecasting generation and retail load

Market maturity and economic conditions

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Ability to utilize tax benefits through carry backs to prior periods and carry forwards to future periods

Impairment of Long-Lived Assets and Investments Recoverability of investment through future operations

Evaluation of Assets for Impairment and Other-Than-Temporary Decline in Value Recoverability of investment through future operations

Regulatory and political environments and requirements

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Fair value estimate of intangible assets acquired in business combinations

Business Combinations Fair value of assets acquired and liabilities assumed in business combinations

Estimated future cash flow

Estimated useful lives of assets

Contingencies Estimated financial impact of event(s)

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Derivative Instruments

The Company follows the guidance of ASC 815 to account for derivative instruments.

ASC 815 requires the Company to mark-to-market all derivative instruments on the balance sheet and recognize changes in the fair value of non-hedge derivative instruments immediately in earnings.

In certain cases, NRG may apply hedge accounting to the Company's derivative instruments.

The criteria used to determine if hedge accounting treatment is appropriate are:

(i) the designation of the hedge to an underlying exposure;

(ii) whether the overall risk is being reduced;

and (iii) if there is a correlation between the changes in fair value of the derivative instrument and the underlying hedged item.

Changes in the fair value of derivatives instruments accounted for as hedges are deferred and recorded as a component of OCI and subsequently recognized in earnings when the hedged transactions occur.

For purposes of measuring the fair value of derivative instruments, NRG uses quoted exchange prices and broker quotes.

The Company follows the guidance of ASC 815, Derivatives and Hedging, or ASC 815, to account for derivative instruments.

ASC 815 requires the Company to mark-to-market all derivative instruments on the balance sheet and recognize fair value change in earnings, unless they qualify for the NPNS exception.

ASC 815 applies to NRG's energy related commodity contracts, interest rate swaps and foreign exchange contracts.

For purposes of measuring the fair value of derivative instruments, the Company uses quoted exchange prices and broker quotes.

When external prices are not available, NRG uses internal models to determine the fair value.

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These estimations are considered to be critical accounting estimates.

Upon repayment of the Term Loan in 2019, all of the Company's interest rate swaps were terminated.

During the fourth quarter of 2020, NRG entered into $1.6 billion of interest rate hedges associated with anticipated certain financing needs.

During the fourth quarter of 2020, the Company entered into $1.6 billion of interest rate hedges associated with anticipated certain financing needs.

As of December 31, 2020, the interest rate hedges were settled in connection with the issuance of fixed rate debt, resulting in a gain of $11 million that was recorded as a reduction to interest expense.

In order to qualify the derivative instruments for hedged transactions prior to termination, NRG estimated the forecasted borrowings for interest rate swaps occurring within a specified time period.

Judgments related to the probability of forecasted borrowings were based on the estimated timing of project construction, which can vary based on various factors.

The probability that forecasted borrowings will occur by the end of a specified time period could change the results of operations by requiring amounts classified in OCI to be reclassified into earnings, creating increased variability in the Company's earnings.

In order to mitigate foreign exchange risk primarily associated with the purchase of USD denominated natural gas for the Company's Canadian business, the Company enters into foreign exchange contract agreements.

Certain derivative instruments that meet the criteria for derivative accounting treatment also qualify for a scope exception to derivative accounting, as they are considered to be NPNS.

The availability of this exception is based upon the assumption

that NRG has the ability and it is probable to deliver or take delivery of the underlying item.

These assumptions are based on expected load requirements, available baseload capacity, internal forecasts of sales and generation and historical physical delivery on contracts.

The availability of this exception is based upon the assumption that the Company has the ability and it is probable to deliver or take delivery of the underlying item.

These assumptions are based on expected load requirements, internal forecasts of sales and generation and historical physical delivery on contracts.

Derivatives that are considered to be NPNS are exempt from derivative accounting treatment and are accounted for under accrual accounting.

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The evaluation of deferred tax assets requires judgment in assessing the likely future tax consequences of events that have been recognized in the Company's financial statements or tax returns and forecasting future profitability by tax jurisdiction.

A valuation allowance of $266 million and $242 million was recorded against NRG’s gross deferred tax asset balance as of December 31, 2020, and December 31, 2019, respectively.

During the year ended December 31, 2019, NRG released the majority of its valuation allowance against its U.S.

federal and state deferred tax assets, resulting in a non-cash benefit to income tax expense of approximately $3.5 billion.

The Company evaluates its deferred tax assets quarterly on a jurisdictional basis to determine whether adjustments to the valuation allowance are appropriate considering changes in facts or circumstances.

As of each reporting date, management considers new evidence, both positive and negative, when determining the future realization of the Company’s deferred tax assets.

In making the determination to release the majority of the valuation allowance as of December 31, 2019, the Company evaluated a number of factors, including its recent history of pre-tax earnings, utilization of $593 million of NOLs in 2019, as well as its forecasted future pre-tax earnings.

Based on this evaluation, the Company determined that its future U.S.

federal tax benefits are more-likely-than-not to be realized.

Given the Company’s current level of pre-tax earnings and forecasted future pre-tax earnings, the Company expects to generate income before taxes in the U.S.

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federal NOL carryforwards and the majority of its state NOL carryforwards prior to their expiration.

NRG continues to maintain a valuation allowance of approximately $266 million as of December 31, 2020 against net deferred tax assets consisting of state net operating losses and foreign NOL carryforwards in jurisdictions where the Company does not currently believe that the realization of its deferred tax assets is more likely than not.

Considerable judgment is required to determine the tax treatment of a particular item that involves interpretations of complex tax laws, including the impact of the Tax Act effective December 22, 2017.

NRG is subject to examination by taxing authorities for income tax returns filed in the U.S.

The Company continues to maintain a valuation allowance of approximately $248 million as of December 31, 2021 against deferred tax assets consisting of state net operating losses and foreign NOL carryforwards in jurisdictions where the Company does not currently believe that the realization of deferred tax assets is more likely than not.

As of December 31, 2020 the Company's valuation allowance balance was $266 million.

Considerable judgment is required to determine the tax treatment of a particular item that involves interpretations of complex tax laws.

The Company is subject to examination by taxing authorities for income tax returns filed in the U.S.

federal jurisdiction and various state and foreign jurisdictions, including operations located in Australia and Canada.

NRG continues to be under audit for multiple years by taxing authorities in various jurisdictions.

The Company continues to be under audit for multiple years by taxing authorities in various jurisdictions.

The Company is no longer subject to U.S.

federal income tax examinations for years prior to 2018.

With few exceptions, state and local income tax examinations are no longer open for years before 2012.

With few exceptions, state and and Canadian income tax examinations are no longer open for years before 2013.

NRG does not intend, nor currently foresee a need, to repatriate funds held at our international operations into the U.S.

These funds are deemed to be indefinitely reinvested in our foreign operations and the Company has not changed its assertion with respect to distributions of funds that would require the accrual of U.S.

Evaluation of Assets for Impairment and Other-Than-Temporary Decline in Value

In accordance with ASC 360, Property, Plant, and Equipment , or ASC 360, NRG evaluates property, plant and equipment and certain intangible assets for impairment whenever indicators of impairment exist.

Examples of such indicators or events are:

In accordance with ASC 360, Property, Plant, and Equipment , or ASC 360, the Company evaluates property, plant and equipment and certain intangible assets for impairment whenever indicators of impairment exist.

Examples of such indicators or events include:

• Significant decrease in the market price of a long-lived asset;

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• Adverse business climate;

• Accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset;

• Accumulation of costs significantly in excess of the amounts originally expected for the construction or acquisition of an asset;

• Current period loss combined with a history of losses or the projection of future losses;

• Change in the Company's intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold, or disposed of before the end of its previously estimated useful life.

Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset, through considering project specific assumptions for long-term power prices, escalated future project operating costs and expected plant operations.

If such assets are considered to be impaired, the

impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets by factoring in the different courses of action available to the Company.

Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the assets to the future net cash flows expected to be generated by the asset, through considering project specific assumptions for long-term power and natural gas prices, escalated future project operating costs and expected plant operations.

If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets by factoring in the different courses of action available to the Company.

Generally, fair value will be determined using valuation techniques, such as the present value of expected future cash flows.

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The estimation of fair value, whether in conjunction with an asset to be held and used or with an asset held-for-sale, and the evaluation of asset impairment are, by their nature, subjective.

NRG considers quoted market prices in active markets to the extent they are available.

In the absence of such information, the Company may consider prices of similar assets, consult with brokers, or employ other valuation techniques.

NRG will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment or asset.

The Company considers quoted market prices in active markets to the extent they are available.

In the absence of such information, NRG may consider prices of similar assets, consult with brokers, or employ other valuation techniques.

The Company will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment or asset.

The use of these methods involves the same inherent uncertainty of future cash flows as previously discussed with respect to undiscounted cash flows.

Actual future market prices and project costs could vary from those used in the Company's estimates and the impact of such variations could be material.

In the third quarter of 2020, the Company concluded its Home Solar business was held for sale as a result of advanced negotiations to sell the business and recorded an impairment loss of $29 million in the West/Other segment to adjust the carrying amount of the assets and liabilities to fair market value based on indicative sale prices.

On November 13, 2020, the Company completed the sale of the Home Solar business for $66 million.

Actual future market prices and project costs could vary from those used in NRG's estimates and the impact of such variations could be material.

During the second quarter of 2021, the results of the PJM Base Residual Auction for the 2022/2023 delivery year were released leading the Company to announce the near-term retirement of a significant portion of its PJM coal generating assets in June 2022.

The Company considered the decline in PJM capacity prices and the near-term retirement dates of certain assets to be a trigger for impairment and performed impairment tests on the PJM generating assets and the goodwill associated with Midwest Generation.

The Company measured the impairment losses on the PJM generation assets and Midwest Generation goodwill as the difference between the carrying amount and the fair value of the PJM generating assets and Midwest Generation reporting unit, respectively.

Fair values were determined primarily using an income approach in which the Company applied a discounted cash flow methodology to the long-term budgets for the plants and reporting unit.

Significant inputs impacting the income approach include the Company's long-term view of capacity and fuel prices, projected generation, the physical and economic characteristics of each plant, and the discount rate applied to the after-tax cash flow projections.

Impairment losses of $271 million and $35 million were recorded in the East segment on the PJM generating assets and Midwest Generation goodwill, respectively.

Annually, during the fourth quarter, the Company revises its views of power and fuel prices including the Company's fundamental view for long-term prices, forecasted generation and operating and capital expenditures, in connection with the preparation of its annual budget.

Changes to the Company's views of long-term power and fuel prices impact the Company’s projections of profitability, based on management's estimate of supply and demand within the sub-markets for its operations and the physical and economic characteristics of each of its businesses.

During 2020, the Company identified a long-lived asset impairment related to the Cottonwood facility, as further described in Item 15 — Note 11 , Asset Impairments .

The Company recognized an impairment loss of $32 million in 2020 in the West/Other segment associated with the Company's long-term services agreement and related lease payments, as the carrying amounts of the assets from the contract were higher than the estimated operating cash flow though the remaining lease period.

In the fourth quarter of 2021, the Company recognized an impairment loss of $213 million in the East segment as a result of changes in the long-term outlook of the Joliet facility prompted by market conditions and an assessment of various alternatives for the long-term operational landscape of the facility including the impact of the CEJA in Illinois, which concluded with the annual budget process.

The Company recorded additional impairment losses of $16 million and $9 million related to various power plants in the East and West/Services/Other segments, respectively.

In the third quarter of 2020, the Company concluded its Home Solar business was held for sale as a result of advanced negotiations to sell the business and recorded an impairment loss of $29 million in the West/Services/Other segment to adjust the carrying amount of the assets and liabilities to fair market value based on indicative sale prices.

On November 13, 2020, the Company completed the sale of the Home Solar business for $66 million.

In the fourth quarter of 2020, the Company recognized an impairment loss of $32 million in the West/Services/Other segment related to the Cottonwood facility.

The impairment was attributable to the Company's long-term services agreement and related lease payments, as the carrying amounts of the assets from the contract were higher than the estimated operating cash flow though the remaining lease period.

Additionally, in the fourth quarter of 2020, the Company recorded $14 million of impairment losses related to intangible assets in the Texas segment.

Equity Method Investments

NRG is also required to evaluate its equity method investments to determine whether or not they are impaired in accordance with ASC 323, Investments - Equity Method and Joint Ventures , or ASC 323.

The standard for determining whether an impairment must be recorded under ASC 323 is whether a decline in the value is considered an other-than-temporary decline in value.

The Company is also required to evaluate for impairment its equity method investments in accordance with ASC 323, Investments - Equity Method and Joint Ventures , or ASC 323.

The standard for determining whether an impairment must be recorded under ASC 323 is whether an observed decline in the value of an equity method investment is considered other-than-temporary.

The evaluation and measurement of impairments under ASC 323 involves the same uncertainties as described for long-lived assets that the Company owns directly and accounts for in accordance with ASC 360.

Similarly, the estimates that NRG makes with respect to its equity method investments are subjective, and the impact of variations in these estimates could be material.

Additionally, if the projects in which the Company holds these investments recognize an impairment under the provisions of ASC 360, NRG would record its proportionate share of that impairment loss and would evaluate its investment for an other-than-temporary decline in value under ASC 323.

During the year ended December 31, 2020, the Company recorded an impairment loss of $18 million in the Texas segment, which included the anticipated drawdown of the $12 million letter of credit posted in September 2019 to cover certain project debt reserve requirements.

Other Impairments

For the year ended December 31, 2020, the Company recorded $14 million of impairment losses related to intangible assets in the Texas segment.

Similarly, the estimates that the Company makes with respect to its equity method investments are subjective, and the impact of variations in these estimates could be material.

Additionally, if the projects in which the Company holds these investments recognize an impairment under the provisions of ASC 360, the Company would record its proportionate share of that impairment loss and would evaluate its investment for an other-than-temporary decline in value under ASC 323.

During the first quarter of 2020, NRG recorded an impairment loss of $18 million in the Texas segment, attributable to its equity method investment in Petra Nova Parish Holdings, which included the anticipated drawdown of the $12 million letter of credit posted in September 2019 to cover certain project debt reserve requirements.

Goodwill and Other Intangible Assets

At December 31, 2020, NRG reported goodwill of $579 million, consisting of $165 million associated with the acquisition of Midwest Generation and $414 million for retail operations acquisitions, including Stream Energy and XOOM, which were acquired in 2019 and 2018, respectively.

The Company applies ASC 805, Business Combinations , or ASC 805, and ASC 350, to account for its goodwill and intangible assets.

At December 31, 2021, the Company reported goodwill of $1.8 billion, consisting of $1.3 billion from the acquisition of Direct Energy in 2021, $130 million associated with the acquisition of Midwest Generation and $414 million for retail operations acquisitions, including Stream Energy, which was acquired in 2019.

The Company applies ASC 805, Business Combinations , or ASC 805, and ASC 350, Intangibles-Goodwill and Other, or ASC 350 to account for its goodwill and intangible assets.

Under these standards, the Company amortizes all finite-lived intangible assets over their respective estimated weighted-average useful lives, while goodwill has an indefinite life and is not amortized.

Goodwill is tested for impairment at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount.

The Company tests goodwill for impairment at the reporting unit

level, which is identified by assessing whether the components of the Company's operating segments constitute businesses for which discrete financial information is available and whether segment management regularly reviews the operating results of those components.

The Company tests goodwill for impairment at the reporting unit level, which is identified by assessing whether the components of the Company's operating segments constitute businesses for which discrete financial information is available and whether segment management regularly reviews the operating results of those components.

The Company performs the annual goodwill impairment assessment as of December 31 or when events or changes in circumstances indicate that the fair value of the reporting unit may be below the carrying amount.

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In the absence of sufficient qualitative factors, the Company performs a quantitative assessment by determining the fair value of the reporting unit and comparing to its book value.

If it is determined that the fair value of a reporting unit is below its carrying amount, where necessary, the Company's goodwill will be impaired at that time.

The Company performed its qualitative assessment of macroeconomic, industry and market events and circumstances, and the overall financial performance of the Texas (Texas segment) and East Retail (East segment) reporting units.

If it is determined that the fair value of a reporting unit is below its carrying amount, the Company's goodwill will be impaired at that time.

An impairment of $35 million was recorded in Midwest Generation goodwill.

For further discussion, see Evaluation of Assets for Impairment and Other-Than-Temporary Decline in Value caption above.

During the fourth quarter of 2021, the Company performed its qualitative assessment of macroeconomic, industry and market events and circumstances, and the overall financial performance of the Texas (Texas segment) and East Retail (East segment) reporting units.

The Company determined it was more-likely-than not that the fair value of the goodwill attributed to these reporting units were more than their carrying amount and accordingly, no impairment existed for the year ended December 31, 2021.

The Company performed a quantitative assessment for the Midwest Generation (East segment) reporting unit.

The Company determined the fair value of the reporting unit using an income approach.

Under the income approach, the Company estimated the fair value of the reporting unit's cash flow exceeded its carrying value and, as such, the Company concluded that goodwill associated with the reporting unit was not impaired as of December 31, 2020.

During the fourth quarter of 2021, the Company also performed a quantitative assessment for the Midwest Generation (East segment) and West/Services/Other reporting units.

The Company determined the fair value of the reporting units using an income approach.

Based on the income approach, the Company estimated the fair value of each reporting units' cash flows exceeded its carrying value and, as such, NRG concluded that the goodwill associated with each reporting unit was not impaired as of December 31, 2021.

The Company believes the methodology and assumptions used in its quantitative assessments were consistent with the views of market participants.

Significant inputs to the determinations of fair value were as follows:

Significant inputs to the determinations of fair value of the Midwest Generation reporting unit were as follows:

• The Company applied a discounted cash flow methodology to the long-term budgets for the Midwest Generation plants, resulting in fair value over the carrying value of the reporting unit of 117%.

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As a result, there can be no assurance that the estimates and assumptions made for purposes of the annual goodwill impairment test will prove to be accurate predictions of the future.

Business Combinations

We account for business acquisitions using the acquisition method of accounting prescribed under ASC 805.

Under this method, we are required to record on our Consolidated Balance Sheets the estimated fair values of the acquired company’s assets and liabilities assumed at the acquisition date.

The excess of the consideration transferred over the fair value of the net identifiable assets acquired and liabilities assumed is recorded as goodwill.

Determining fair values of assets acquired and liabilities assumed requires significant estimates and judgments.

We determine fair value based on the estimated price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

The acquired assets and assumed liabilities that involved the most subjectivity in determining fair value consisted of the trade names, customer relationships and derivative contracts.

The fair value of trade names and customer relationships was measured using income-based valuation methodologies, which include certain assumptions such as forecasted future cash flows, customer attrition rates, royalty rates and discount rates.

The trade names are amortized to depreciation and amortization, on a straight line basis.

The customer relationships are amortized to depreciation and amortization, ratably based on discounted future cash flows.

In measuring the fair value of derivative contracts, a significant portion of the fair value of the derivative portfolio was based on price quotes from brokers in active markets who regularly facilitate those transactions and the Company believes such price quotes are executable.

The Company does not use third party sources that derive price based on proprietary models or market surveys.

The remainder of the assets and liabilities represents contracts for which external sources or observable market quotes are not available.

These contracts were valued based on various valuation techniques including but not limited to internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics.

The fair value of each contract was discounted using a risk free interest rate.

In addition, the Company applied a credit reserve to reflect credit risk.

NRG describes in detail its acquisitions in Item 15 — Note 4, Acquisitions, Discontinued Operations and Dispositions , to the Consolidated Financial Statements

Contingencies

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What changed 10-K

Item 7. Management’s Discussion and Analysis