What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2023-02-23 compared with 2022-02-24 · 349 added, 413 removed, 645 unchanged (54% of the section changed)

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• Results of operations for the years ended December 31, 2022 and December 31, 2021, including an explanation of significant differences between the periods in the specific line items of NRG's Consolidated Statements of Operations;

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

• Liquidity and capital resources including liquidity position, financial condition addressing credit ratings, material cash requirements and commitments, and other obligations;

• 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.

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A discussion and analysis of fiscal year 2020 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, 2021.

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

• South Central Portfolio

• NRG Yield, Inc.

and its Renewables Platform

Executive Summary

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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.

The Company has a customer base that includes approximately 5.4 million Home customers as well as commercial, industrial, and wholesale customers, supported by approximately 16 GW of generation as of December 31, 2022.

Business Environment

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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.

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, global LNG demand, exports of natural gas, and the financial and hedging profile of natural gas customers and producers.

In 2022, the average natural gas price at Henry Hub was 73% higher than in 2021.

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

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

Natural gas prices are a primary driver of coal demand.

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

NRG may experience impacts to gross margins due to significant, rapid changes in current natural gas prices and the lag in its ability to make a corresponding adjustment to the retail rates it charges 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 it is able to make the corresponding adjustments to the retail customer rates.

The relative price of natural gas as compared to coal is the primary driver of coal demand.

Coal commodity prices decreased in 2022 although supply chain disruptions are still affecting coal deliveries, as further discussed below in Global Supply Chain Disruptions.

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, 2022 and 2021.

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.

The average on-peak power prices decreased significantly in Texas due to Winter Storm Uri's impact on 2021 pricing.

East and West average on-peak prices increased as a result of 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 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

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 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.

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 1.5 degrees Celsius.

As a result, policymakers and regulators at regional, national, sub-national and local levels of government, both in the U.S.

and other parts of the world, are increasingly focused on actions to combat climate change.

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

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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 issued a stand-alone TCFD report in December 2021.

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

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

In addition, the costs associated with the development of lower carbon infrastructure, such as wind and solar generating facilities, continue to decline.

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

Inflation Reduction Act, signed into law in August 2022, is intended to further support the deployment of lower carbon energy technologies.

As costs associated with the development of lower carbon infrastructure, such as wind and solar generating facilities, continue to evolve and impact development of lower carbon infrastructure in the markets where the Company participates, it may impact the ability of the Company's generating facilities to participate in those markets.

According to ERCOT, 41% of 2022 energy consumption in the ERCOT market was generated from carbon emission-free resources, with wind power contributing 25%.

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

In addition, as subsidies and incentives contribute to increases in renewable power sources, customer awareness and preferences are shifting toward sustainable solutions.

Increased demand for sustainable energy products from both residential and commercial customers creates opportunities for diversified product offerings in competitive retail markets.

Digitization and Customization — The electric industry is experiencing major technology changes in the way power is distributed and used by end-use customers.

Digitization and Customization — The electric industry is experiencing major technology changes in the way power is distributed and consumed by end-use customers.

The electric grid is shifting from a centralized analog system, where power is generated from limited sources and flows in one direction, to a decentralized multidirectional system, where power can be generated from a number of distributed resources and stored or dispatched on an as-needed basis.

In addition, customers are seeking new ways to engage with their power providers.

Technologies like smart thermostats, appliances and electric vehicles are giving individuals more choice and control over their electricity usage.

Technologies like smart thermostats, smart appliances and electric vehicles are giving individuals more choice and control over their electricity usage.

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

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typically do not experience extreme weather conditions at the same time, thus NRG's operations are typically not exposed to the effects of extreme weather in all parts of its business at once.

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

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

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

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

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

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

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

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

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

These supply chain disruptions are due in part to a number of factors outside the Company's control including geopolitical conflicts, public policy of the federal government, 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 retail customers.

The Company expects that supply chain disruptions will continue throughout the remainder of 2023.

NRG is working closely with its suppliers and customers to minimize any potential adverse impacts of these events.

The Company 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 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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• extreme peak demands;

• performance of renewable generation;

• available supply resources;

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The following significant events occurred during 2022 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

Vivint Acquisition

On December 6, 2022, NRG and Vivint Smart Home, Inc.

announced the entry into a definitive agreement under which the Company will acquire Vivint in an all-cash transaction.

The Company will pay $12 per share, or approximately $2.8 billion in cash, and expects to fund the acquisition using proceeds from newly issued debt and preferred equity, drawing on its Revolving Credit Facility and Receivables Securitization Facilities, and through cash on hand.

Additionally, in the first quarter of 2023, NRG increased its Revolving Credit Facility by $600 million to meet the additional liquidity requirements related to the acquisition.

Close of the acquisition is targeted for the first quarter of 2023 and is subject to customary closing conditions.

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

On January 6, 2023, NRG closed on the sale of land and related assets from the Astoria site, within the East region of operations, for initial proceeds of $212 million subject to transaction fees of $3 million and certain indemnifications.

As part of the transaction, NRG entered into an agreement to lease the land back for the purpose of operating the Astoria gas turbines through the planned April 30, 2023 retirement date.

The operating lease agreement is expected to end six months after the facility's actual retirement date.

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

Sale of Watson

On June 1, 2022, the Company closed on the sale of its 49% ownership in the Watson natural gas generating facility for $59 million.

NRG recognized a gain on the sale of $46 million.

Retirement of Joliet

During the second quarter of 2022, the results of the PJM Base Residual Auction for the 2023/2024 delivery year were released leading the Company to revise its long-term view of certain facilities and announce the planned retirement of the Joliet generating facility on June 1, 2023.

Impairment losses of $20 million and $130 million were recorded on the PJM generating assets and Midwest Generation goodwill, respectively.

Parish Extended Outage

In May 2022, W.A.

Parish Unit 8 came offline as a result of damage to the steam turbine/generator.

Based on work completed to date, NRG is targeting to return the unit to service by the end of the second quarter of 2023.

The Company is working with its insurers related to claims surrounding the outage and has received partial settlements in the fourth quarter of 2022.

Limestone Unit 1 Return to Service

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

The extended forced outage ended in April of 2022 and the unit has returned to service.

ERCOT 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.

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

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

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

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

Direct Energy Acquisition

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

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

states and 8 Canadian provinces.

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

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

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

Limestone Extended Outage

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

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

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

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

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

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

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

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

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

Sale of 4.8 GW of Fossil Generation Assets

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

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

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

Sale of Agua Caliente

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

for $202 million.

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

In 2021, the Texas Legislature passed HB 4492 for ERCOT to mitigate exceptionally high price adders and ancillary service costs incurred by LSEs during Winter Storm Uri.

HB 4492 authorized ERCOT to obtain $2.1 billion of financing to distribute to LSEs that were charged and paid to ERCOT those highly priced ancillary service and ORDPA during Winter Storm Uri.

The Company accounted for the proceeds as a reduction to cost of operations within its Consolidated Statements of Operations in the 2021 annual period for which the proceeds were intended to compensate.

The Company received the proceeds of $689 million from ERCOT in June 2022.

Share Repurchases

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

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

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

In December 2021, the Company's board of directors authorized the Company to repurchase $1.0 billion of its common stock, of which $44 million was repurchased in 2021.

During the year ended December 31, 2022, the Company repurchased $601 million of shares at an average price of $40.50 per share, including $6 million of equivalent shares purchased in lieu of tax withholdings on equity compensation issuances.

The remaining $355 million repurchases under the $1.0 billion authorization are expected to be repurchased in 2023, subject to the availability of excess cash and full visibility of the achievement of the Company's 2023 targeted credit metrics.

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

Renewable Power Purchase Agreements

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

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

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

As of December 31, 2022, NRG has entered into Renewable PPAs totaling approximately 2.4 GW, of which approximately 45% are operational.

The average tenor of these agreements is twelve years.

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

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

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

Dividend Increase

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Year Ended December 31,

(In millions, except otherwise noted) 2021 2020 Change

Operating Revenues

(In millions, except otherwise noted) 2022 2021 (a)

Retail revenue $ 29,722 $ 23,561 $ 6,161

Energy revenue (a)

Energy revenue (b)

1,250 1,215 35

Capacity revenue (a)

Capacity revenue (b)

272 775 (503)

Mark-to-market for economic hedging activities (83) (164) 81

Contract amortization (39) (30) (9)

Other revenues (a)(b)

Other revenues (b)(c)

421 1,632 (1,211)

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

Total revenues 31,543 26,989 4,554

Operating Costs and Expenses

Cost of fuel 1,919 1,840 (79)

Purchased energy and other cost of sales (c)

Purchased energy and other cost of sales (d)

24,984 19,770 (5,214)

Mark-to-market for economic hedging activities (1,331) (2,880) (1,549)

Contract and emissions credit amortization (c)

Contract and emissions credit amortization (d)

Operations and maintenance 1,352 1,370 18

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Equity in earnings of unconsolidated affiliates 6 17 (11)

Impairment losses on investments — (18) 18

Other income, net 56 63 (7)

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Average natural gas price — Henry Hub ($/MMBtu) $ 6.64 $ 3.84 73 %

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

(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.

(a) Includes the impact of Winter Storm Uri

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

(d) Includes amortization of SO 2 and NO x credits and excludes amortization of RGGI credits

The Company calculates gross margin in order to evaluate operating performance as 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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Contract amortization — (40) 1 — (39)

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

Operating revenue (a)

Other revenue (a)

327 104 5 (15) 421

Total revenue 10,057 16,763 4,706 17 31,543

Cost of fuel (1,213) (376) (330) — (1,919)

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GWh sold 37,275 10,832 6,676 — 54,783

GWh generated (b) (c)

GWh generated (b)

37,275 7,282 6,676 — 51,233

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

The whole home warranty business was sold in January 2022

(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, 2021

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

Other revenue 222 62 43 (8) 319

Operating revenue 6,309 2,258 530 (4) 9,093

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

Other revenue (a)

1,565 51 25 (9) 1,632

Total revenue 10,295 13,025 3,659 10 26,989

Cost of fuel (1,424) (196) (220) — (1,840)

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

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

(6,107) (10,774) (2,887) (2) (19,770)

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Economic gross margin $ 2,767 $ 2,169 $ 642 $ (5) $ 5,573

(a) Includes capacity and emissions credits

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

(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

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

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

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

Home natural gas retail sales volumes (MDth) — 50,417 97,272 — 147,689

Business natural gas retail sales volumes (MDth) — 1,620,036 109,021 — 1,729,057

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

3,040 1,844 977 — 5,861

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

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

3,010 1,766 946 — 5,722

GWh sold 36,920 11,452 8,503 — 56,875

GWh generated (b)(c)

GWh generated (c)(d)

36,920 7,494 7,949 — 52,363

(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

(b) Includes 135 thousand whole home warranty customers in West/Services/Other.

The whole home warranty business was sold in January 2022

(d) Includes 1,054 GWh and 2,445 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 2022 and 2021:

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

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

A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region.

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

A Heating Degree Day ("HDD"), represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region.

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

Winter Storm Uri

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 $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.

Gross margin decreased $2.2 billion and economic gross margin decreased $811 million, both of which include intercompany sales, during the year ended December 31, 2022, compared to the same period in 2021.

The detail by segment is as follows:

(In millions)

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

Lower gross margin due to the impact of Winter Storm Uri in 2021, primarily driven by hedging optimization, partially offset by the negative impact of an increase in unhedgeable ancillary and operating reserve demand curve (a) , net of securitization proceeds of $689 million

The following explanations exclude the impact of Winter Storm Uri:

Higher gross margin due to increased volumes from the acquisition of Direct Energy in January 2021 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

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

Lower gross margin due to the net effect of:

• a 40%, or $1 billion increase in overall average costs to serve the retail load, driven by increases in power, ancillary, and fuel costs, an extended outage at W.A.

Parish Unit 8 and the more conservative winter hedge profile in the first quarter of 2022, partially offset by the favorable impact of the early settlement of a solar PPA and partial settlements of business interruption insurance claims related to W.A.

Parish and Limestone extended outages;

• increased net revenue rates of $9.50 per MWh, or $611 million primarily driven by changes in customer term, product and mix

Higher gross margin due to an increase in load due to weather of 5.3 million MWhs, or $185 million and an increase in load of 220k MWhs, or $58 million, primarily driven by changes in customer mix 243

Lower gross margin from market optimization activities (40)

Decrease in economic gross margin $ (304)

Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges (372)

Increase in contract and emission credit amortization (2)

Decrease in depreciation and amortization 26

Decrease in gross margin $ (652)

(a) For further discussion of ERCOT's securitization activity see Regional Regulatory Development s section under Regulatory Matters in Item 1 - Business

(In millions)

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

Lower gross margin due to the impact of Winter Storm Uri in 2021, 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 (211)

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

Lower gross margin due to a decrease in generation and capacity as a result of Midwest Generation asset retirements in the second quarter of 2022 (91)

Lower gross margin due to a 32% decrease in PJM capacity prices and a 45% decrease in New York capacity prices coupled with net Capacity Performance penalties resulting from Winter Storm Elliott in December 2022 (109)

Lower demand response gross margin primarily due to a decrease in early settlements of capacity obligations in 2022 compared to 2021 (94)

Lower electric gross margin from decreased load of 6.7 TWh due to attrition and change in customer mix (71)

Lower electric gross margin due to higher supply costs of $15.25 per MWh.

driven primarily by increases in power prices, totaling $931 million, partially offset by higher net revenue rates as a result of changes in customer term, product and mix of $14.50 per MWh, or $888 million (43)

Higher gross margin primarily at Midwest Generation due to a 31% increase in average realized pricing and an increase in generation volumes due to dark spread expansion, partially offset by increased supply costs 33

Higher gross margin from the sales of NO x emission credits

Higher natural gas gross margin including the impact of transportation and storage contract optimization, resulting in higher net revenue rates from changes in customer term, product and mix of $2.25 per Dth, or $3.8 billion, partially offset by higher supply costs of $2.15 per Dth, or $3.6 billion 219

Decrease in economic gross margin $ (494)

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 amortization (77)

Increase in depreciation and amortization (200)

Increase in gross margin $ 2,401

Decrease in depreciation and amortization 125

Decrease in gross margin $ (1,973)

West/Services/Other

(In millions)

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

Lower gross margin due to the impact of Winter Storm Uri in 2021, primarily driven by natural gas optimization during volatile pricing that occurred during the weather event $ (13)

The following explanations exclude the impact of Winter Storm Uri:

Higher gross margin due to 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 sale of fossil generating assets to Generation Bridge in December 2021 (86)

Increase in economic gross margin $ 347

Lower gross margin due to the sale of the whole home warranty business in the first quarter of 2022 (21)

Higher gross margin at Cottonwood due to a 84% increase in average realized power prices as well as an anticipated Capacity Performance bonus payment from PJM as a result of Winter Storm Elliott, partially offset by increased commodity costs 95

Higher gross margin primarily due to increased revenue at Airtron 25

Higher electric gross margin due to higher revenue rates of $26.50 per MWh, totaling $331 million, partially offset by higher supply costs of $26.00 per MWh, or $322 million from changes in customer term, product and mix 8

Lower natural gas gross margin due to higher supply costs of $1.65 per Dth, totaling $403 million, partially offset by higher net revenue rates of $1.40 per Dth, or $346 million and an increase in load due to changes in customer mix of $33 million (24)

Decrease in economic gross margin $ (15)

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)

Decrease in contract amortization 2

Decrease in depreciation and amortization 3

Increase in gross margin $ 421

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

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

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

Total net mark-to-market results decreased by $1.5 billion during the year ended December 31, 2022, compared to the same period in 2021.

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

Year Ended December 31, 2022

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

Mark-to-market results in operating revenues

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

Mark-to-market results in revenues

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

$ 2 $ (5) $ 40 $ (8) $ 29

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— (22) (96) 9 (109)

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

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

$ 2 $ (30) $ (56) $ 1 $ (83)

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(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

Mark-to-market results in revenues

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 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

Mark-to-market results consist of unrealized gains and losses on contracts that are yet to be settled.

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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.

For the year ended December 31, 2022, the $83 million loss in revenues from economic hedge positions was driven by a decrease in the value of open positions as a result of increases in power prices across all segments, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period.

The $1.3 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 partially offset by the reversal of previously recognized unrealized gains on contracts that settled during the period.

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

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

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

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

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the years ended December 31, 2022 and 2021.

The realized and unrealized financial and physical trading results are included in operating revenue.

The realized and unrealized financial and physical trading results are included in revenue.

The Company's trading activities are subject to limits within the Company's Risk Management Policy.

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

Operations and maintenance expenses increased by $241 million for the year ended December 31, 2021 compared to the same period in 2020, due to the following:

Operations and maintenance expenses decreased by $18 million for the year ended December 31, 2022, compared to the same period in 2021, due to the following:

(In millions)

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 $ (90)

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

Increase in operations and maintenance expense $ 241

Decrease due to current year settled property insurance claims for extended outages at W.A.

Parish and Limestone, primarily offset by the cost of restoration efforts at W.A.

Parish in 2022 (35)

Decrease due to Midwest Generation asset retirements in the second quarter of 2022 as well as spare parts inventory reserves in 2021 (20)

Decrease driven by current year scrap proceeds associated with the demolition of the Encina site (4)

Decrease driven by higher maintenance in 2021 resulting from the impacts of Winter Storm Uri (2)

Increase due to scope of outages at the Texas coal and gas facilities (excluding W.A.

Parish included above) in 2022, partially offset by a prior year planned outage at STP 69

Increase in variable operation and maintenance expense at the PJM coal facilities associated with increased generation during 2022 39

Increase in estimates of environmental remediation costs at deactivated sites in the East and West/Services/Other 25

Increase driven by higher retail operations costs primarily to support growth at Airtron 6

Decrease in operations and maintenance expense $ (18)

Other Cost of Operations

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(In millions)

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)

Decrease due to the sale of fossil generating assets to Generation Bridge in December 2021 $ (30)

Increase in retail gross receipt taxes due to higher revenues 51

Increase due to changes in current year ARO cost estimates, primarily at Jewett Mine 28

Increase due to higher property insurance premiums 18

Increase in other cost of operations $ 72

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Year Ended December 31, 2021 336 333 88 28 785

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.

Depreciation and amortization expense decreased by $151 million for the year ended December 31, 2022 compared to the same period in 2021, primarily due to lower depreciation as a result of asset impairments, sales, and retirements, as well as lower amortization as a result of the expected roll off of acquired intangibles.

Impairment Losses

During the year ended December 31, 2022, the Company recorded impairment losses of $206 million, of which $150 million were related to the decline in PJM capacity prices and the near-term retirement date of the Joliet facility, $43 million related to the purchase and sale agreement for the sale of the land and related assets at the Astoria generating site and the planned withdrawal and cancellation of its proposed Astoria redevelopment project, and an additional $13 million in the East segment.

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 .

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

Selling, general and administrative costs increased by $483 million for the year ended December 31, 2021 compared to the same period in 2020, due to the following:

Selling, general and administrative costs decreased by $65 million for the year ended December 31, 2022 compared to the same period in 2021, due to the following:

(In millions)

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

Decrease due to Winter Storm Uri, including charitable giving, legal and other costs of $20 million in 2021, ERCOT default charges of $9 million in 2021, and the reversal of the ERCOT default charges of $9 million in 2022 $ (38)

Decrease in personnel costs (30)

Decrease in transition service agreement costs related to the Direct Energy acquisition (21)

Decrease in marketing and media expenses (17)

Increase in broker fee expenses, partially offset by lower commissions expenses 22

Increase due to higher consulting expenses including spending related to Company's growth initiatives 13

Decrease in selling, general and administrative costs $ (65)

Provision for Credit Losses

3 unchanged sentences

Year Ended December 31, 2021 678 8 12 698

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:

Provision for credit losses decreased by $687 million for the year ended December 31, 2022, compared to the same period in 2021, 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

Decrease due to Winter Storm Uri, including :

Decrease of $403 million related to bilateral financial hedging risk in 2021 as well as $70 million of loss mitigation in 2022

Decrease of $126 million related to counterparty credit risk in 2021 as well as $12 million of loss mitigation in 2022

Decrease of $67 million related to ERCOT default shortfall payments in 2021 as well as $44 million of loss mitigation in 2022

Increase due to higher revenues and deteriorated customer payment behavior 35

Decrease in provision for credit losses $ (687)

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.

Acquisition-related transaction and integration costs were $52 million for the year ended December 31, 2022, which included $34 million of integration costs, primarily related to Direct Energy, and $18 million of acquisitions costs, primarily related to the planned acquisition of Vivint.

Acquisition-related transaction and integration costs of $93 million were incurred during the year ended December 31, 2021, related to Direct Energy, of which $25 million were acquisition-related transaction costs and $68 million were integration costs, primarily related to employee costs, software costs and consulting services.

Gain on Sale of Assets

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

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

Impairment Losses on Investments

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

The gain on sale of assets of $52 million and $247 million recorded for the years ended December 31, 2022 and 2021, respectively, include:

As of December 31,

(In millions) 2022 2021

Sale of 4,850 MW of fossil generating assets to Generation Bridge in December of 2021 $ (3) $ 210

Sale of the Company's 49% ownership in the Watson natural gas generating facility 46 —

Sale of the Company's 50% ownership in Petra Nova 22 —

Sale of a deactivated site in November 2021 — 20

Sale of Agua Caliente in February 2021 — 17

Other asset sales (13) —

Gain on sale of assets $ 52 $ 247

Loss on Debt Extinguishment

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

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

Interest Expense

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

Interest expense decreased by $68 million for the year ended December 31, 2022, compared to the same period in 2021, primarily due to debt reduction and the refinancing of debt to lower interest rates in the second half of 2021.

Income Tax Expense

For the year ended December 31, 2022, NRG recorded income tax expense of $442 million on pre-tax income of $1.7 billion.

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

For the same period in 2021, NRG recorded income tax expense of $672 million on pre-tax income of $2.9 billion.

The effective tax rate was 26.6% and 23.5% for the years ended December 31, 2022 and 2021, respectively.

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

For the year ended December 31, 2022, 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 the recognition of carbon capture tax credits.

Year Ended December 31,

(In millions, except effective income tax rate) 2022 2021

Income from continuing operations before income taxes $ 2,859 $ 761

Income before income taxes $ 1,663 $ 2,859

Tax at federal statutory tax rate 349 600

5 unchanged sentences

Return to provision adjustments — 5

Carbon capture tax credits (19) —

Recognition of uncertain tax benefits 8 (10)

1 unchanged sentence

Effective income tax rate 26.6 % 23.5 %

The effective income tax rate may vary from period to period depending on, among other factors, the geographic and business mix of earnings and losses and changes in valuation allowances in accordance with ASC 740, Income Taxes, or ASC 740.

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

5 unchanged sentences

Cash and cash equivalents:

$ 250 $ 3,905

Restricted cash - operating 5 4

5 unchanged sentences

(b) Total capacity of Revolving Credit Facility and collective collateral facilities was $6.4 billion and $5.9 billion as of December 31, 2022 and December 31, 2021, 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.

As of December 31, 2022, total liquidity, excluding collateral funds deposited by counterparties, increased by $108 million.

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

3 unchanged sentences

Credit Ratings

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

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

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

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

On December 6, 2022, following the Vivint acquisition announcement, Standard & Poor's placed NRG's issuer credit of BB+ on CreditWatch with negative implications.

Concurrently, Fitch assigned NRG a first-time issuer Default Rating of BB+ with a stable outlook.

There was no change to Moody's rating during the year ended December 31, 2022.

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

S&P Moody's Fitch

NRG Energy, Inc.

BB+ Stable Ba1 Stable

3.75% Senior Secured Notes, due 2024 BBB- Baa3

2.00% Senior Secured Notes, due 2025 BBB- Baa3

2.45% Senior Secured Notes, due 2027 BBB- Baa3

6.625% Senior Notes, due 2027 BB+ Ba2

5.75% Senior Notes, due 2028 BB+ Ba2

3.375% Senior Notes, due 2029 BB+ Ba2

4.45% Senior Secured Notes, due 2029 BBB- Baa3

5.25% Senior Notes, due 2029 BB+ Ba2

3.625% Senior Notes, due 2031 BB+ Ba2

3.875% Senior Notes, due 2032 BB+ Ba2

Revolving Credit Facility, due 2024 BBB- Baa3

BB+ Negative Ba1 Stable BB+ Stable

3.75% Senior Secured Notes, due 2024 BBB- Baa3 BBB-

2.00% Senior Secured Notes, due 2025 BBB- Baa3 BBB-

2.45% Senior Secured Notes, due 2027 BBB- Baa3 BBB-

6.625% Senior Notes, due 2027 BB+ Ba2 BB+

5.75% Senior Notes, due 2028 BB+ Ba2 BB+

3.375% Senior Notes, due 2029 BB+ Ba2 BB+

4.45% Senior Secured Notes, due 2029 BBB- Baa3 BBB-

5.25% Senior Notes, due 2029 BB+ Ba2 BB+

3.625% Senior Notes, due 2031 BB+ Ba2 BB+

3.875% Senior Notes, due 2032 BB+ Ba2 BB+

Revolving Credit Facility, due 2024 BBB- Baa3 BBB-

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.

5 unchanged sentences

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

Direct Energy Acquisition

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

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

states and 8 Canadian provinces.

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

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

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

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)

Available on Acquisition Closing Date

Revolving Credit Facility commitment increase $ 802

Revolving Credit Facility new tranche 273

Facility agreement in connection with the sale of pre-capitalized trust securities 874

Available as of December 31, 2020

Credit default swap facility 150

Revolving accounts receivable financing facility 750

Repurchase facility 75

Bilateral letter of credit facilities 475

Total Increases to Liquidity and Collateral Facilities $ 3,399

Planned Debt Reduction

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

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

Issuance of 2032 Senior Notes

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

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

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

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

Senior Note Redemptions

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

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

Receivables Facility

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

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

Repurchase Facility

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

The Company remains committed to maintaining a strong balance sheet and continues to work to achieve investment grade credit metrics over time primarily through debt reduction and the realization of growth initiatives.

ERCOT Securitization Proceeds

In 2021, the Texas Legislature passed HB 4492 for ERCOT to mitigate exceptionally high price adders and ancillary service costs incurred by LSEs during Winter Storm Uri.

HB 4492 authorized ERCOT to obtain $2.1 billion of financing to distribute to LSEs that were charged and paid to ERCOT those highly priced ancillary service and ORDPA during Winter Storm Uri.

The Company received the proceeds of $689 million from ERCOT in June 2022 .

Winter Storm Uri Credit Loss Recoveries

During Winter Storm Uri, in February 2021, the Company experienced nonperformance by a counterparty in one of its bilateral financial hedging transactions, resulting in exposure of $403 million.

During December 2022, the Company received $70 million as part of the Company's loss mitigation efforts in settlement of this exposure.

Brazos Electric Cooperative Bankruptcy

As further discussed in Item 1 — Business, Regulatory Matters , the Company received $29 million as a result of Brazos' chapter 11 plan and the related ERCOT settlement.

Revolving Credit Facility

On February 14, 2023, the Company amended its Revolving Credit Facility to:

(i) increase the existing revolving commitments thereunder by $600 million, (ii) extend the maturity date of a portion of the revolving commitments thereunder to February 14, 2028, (iii) transition the benchmark rate applicable to revolving loans from LIBOR to SOFR and (iv) make certain other amendments to the terms of the Revolving Credit Facility for purposes of, among other things, providing additional flexibility.

See Note 13, Long-term Debt and Finance Leases for further discussion.

Receivables Securitization Facilities

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.

On July 26, 2022, the Company renewed its existing Repurchase Facility to extend the maturity date to July 26, 2023.

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

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

Sale of 4.8 GW of Fossil Generation Assets

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

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

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.

As of December 31, 2022, there were no outstanding borrowings.

On July 26, 2022, NRG Receivables LLC, a wholly-owned indirect subsidiary of the Company, entered into an amendment to its Receivables Facility dated September 22, 2020, with a group of conduit lenders and banks and Royal Bank of Canada, as Administrative Agent to, among other things, (i) extend the scheduled termination date by one year, (ii) increase the aggregate commitments from $800 million to $1.0 billion, (iii) increase the letter of credit sublimit to equal the aggregate commitments, (iv) replace LIBOR with Term SOFR as the benchmark for borrowings and (v) add new originators.

The weighted average interest rate related to usage under the Receivables Facility as of December 31, 2022 was 0.844%.

As of December 31, 2022, there were no outstanding borrowings and there were $721 million in letters of credit issued under the Receivables Facility.

Bilateral Letter of Credit Facilities

On April 29, 2022, May 27, 2022 and October 13, 2022, the Company increased the size of the facilities by $100 million, $50 million and $50 million, respectively, to provide additional liquidity, allowing for the issuance of up to $675 million of letters of credit.

As of December 31, 2022, $668 million was issued under these facilities.

Vivint Acquisition

On December 6, 2022, NRG and Vivint announced the entry into a definitive agreement under which the Company will acquire Vivint in an all-cash transaction.

Additionally, in the first quarter of 2023, NRG increased its Revolving Credit Facility by $600 million to meet the additional liquidity requirements related to the acquisition.

Close of the acquisition is targeted for the first quarter of 2023 and is subject to customary closing conditions.

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

On January 6, 2023, the Company closed on the sale of land and related assets from the Astoria site, within the East region of operations, for initial proceeds of $212 million subject to transactions fees of $3 million and certain indemnifications.

As part of the transaction, NRG entered into an agreement to lease the land back for the purpose of operating the Astoria gas turbines through the planned April 30, 2023, retirement date.

The operating lease agreement is expected to end six months after the facility's actual retirement date.

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

Sale of Watson

On June 1, 2022, the Company closed on the sale of its 49% ownership in the Watson natural gas generating facility for $59 million.

NRG recognized a gain on the sale of $46 million.

Parish Extended Outage

In May 2022, W.A.

Parish Unit 8 came offline as a result of damage to certain components of the steam turbine/generator.

Based on work completed to date, the Company is targeting to return the unit to service by the end of the second quarter of 2023.

The Company is working with its insurers related to claims surrounding the outage and has received partial settlements in the fourth quarter of 2022.

On March 27, 2020, the U.S.

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

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

Pension Plan Contribution

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

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

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

Pension and Other postretirement benefits minimum funding requirements

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

Of this amount, $13 million related to certain 2019 employer payroll taxes was paid in 2022.

All deferred employer payroll taxes have been repaid as of December 31, 2022.

Pension and Other postretirement benefit contributions

As of December 31, 2022, the Company’s estimated pension minimum funding requirements for the next 5 years were $171 million, of which $83 million are required to be made within the next 12 months.

As of December 31, 2022, the Company’s estimated other postretirement benefits minimum funding requirements for the next 5 years were $32 million, of which $7 million are required to be made within the next 12 months.

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Finance leases 4 4 2 1 — — 11

Subtotal Finance Leases 4 3 3 2 — 1 13

Total Debt and Finance Leases $ 63 $ 604 $ 749 $ 1 $ 1,275 $ 5,419 $ 8,111

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As of December 31, 2022, market operations had total cash collateral outstanding of $260 million and $4.0 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.

As of December 31, 2022, total funds deposited by counterparties were $1.7 billion in cash and $888 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, 2022, the Company had minimum payment obligations under such outstanding agreements of $452 million, with $110 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.

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.

As of December 31, 2022, the Company had minimum purchased energy commitments under long-term contracts of $4.3 billion, with $908 million payable within the next 12 months, and an additional $1.5 billion of short-term purchase energy commitments.

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

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Equivalent Net Sales Secured by First Lien Structure (a)

In MW 653 738

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

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

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

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

Capital Expenditures

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Total capital expenditures and investments $ (235) $ (1) $ (249) $ (485)

(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.

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.

(a) Includes other investments, acquisitions and integration projects

Growth investments for the year ended December 31, 2022, include expenditures for small book acquisitions, service acquisitions, integration operating expenses, as well as the Encina site improvements classified as ARO payments.

NRG has completed its demolition activities at the site and has begun marketing the site.

Environmental Capital Expenditures Estimate

NRG estimates that environmental capital expenditures from 2023 through 2027 required to comply with environmental laws will be approximately $42 million.

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

The largest component is the cost of complying with ELG at the Company's 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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Parish 8 TX FGD 1982 SCR 2004 ACI 2015 FF 1988

Waukegan 7 IL DSI 2014 LNBOFA 2002 ACI 2008 ESP/upgrade 1958/2002, 2014

Waukegan 8 IL DSI 2015 LNBOFA 1999 ACI 2008 ESP/upgrade 1962/1999, 2015

Will County 4 IL DSI 2017 LNBOFA 1999,2000 ACI 2009 ESP/upgrade 1963,72/

ACI - Activated Carbon Injection

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(In millions) Total

Asset Sales Target

NRG is targeting additional asset sales with projected proceeds, net of any required deleveraging, of $500 million during 2023.

Share Repurchases

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

In December 2021, the Company's board of directors authorized the Company to repurchase $1.0 billion of its common stock, of which $44 million was repurchased in 2021.

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

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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.

Other liabilities — Other liabilities includes water right agreements, service and maintenance agreements, stadium naming rights, stadium sponsorships, long-term service agreements and other contractual obligations.

As of December 31,

2022, the Company had total of $266 million under such commitments, of which $66 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.

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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.

Variable interest in Equity investments — NRG's investment in Ivanpah is a variable interest entity for which NRG is not the primary beneficiary.

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.

NRG's pro-rata share of non-recourse debt was approximately $478 million as of December 31, 2022.

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

Cash Flow Discussion

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(In millions) 2022 2021 Change

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

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:

Cash provided by operating activities $ 360 $ 493 $ (133)

Cash used by investing activities (332) (3,039) 2,707

Cash provided/(used) by financing activities 1,043 (272) 1,315

Cash provided by operating activities

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

(In millions)

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 $ (1,161)

Increase due to receipt of uplift securitization proceeds from ERCOT in 2022 689

Increase in working capital primarily attributable to the impact of higher market prices on accounts payable, partially offset by a decrease working capital related to higher priced natural gas inventory and accounts receivable 300

Changes in cash collateral in support of risk management activities due to change in commodity prices 99

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

Net Cash (Used)/Provided By Investing Activities

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

Other changes in working capital primarily driven by lower personnel costs (60)

Cash used by investing activities

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

(In millions)

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

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

Increase as a result of less cash paid for acquisitions of assets primarily for Direct Energy in 2021 $ 3,497

Decrease in proceeds from sale of assets primarily due to the prior year's sales of the fossil generating assets and Agua Caliente (721)

Increase in capital expenditures (98)

Increase due to fewer purchases of investments in nuclear decommissioning trust fund securities, net of sales 35

Decrease in sales of emissions allowances (6)

Cash provided/(used) by financing activities

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

(In millions)

Increase primarily due to prior year repayments of long-term debt $ 1,856

Decrease in proceeds from issuance of long-term debt (1,100)

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

Increase in net receipts from settlement of acquired derivatives 1,057

Decrease in payments for share repurchase activity 181

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

Increase in payments for share repurchase activity (558)

Increase due to payments of debt extinguishment costs and deferred issuance costs in 2021 74

Increase in payments of dividends to common stockholders (13)

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For the year ended December 31, 2022, the Company utilized U.S.

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

federal NOLs of $206 million due to current year taxable income, and tax credits of $8 million.

As of December 31, 2022, the Company has cumulative U.S.

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

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

federal NOL carryforwards of $8.2 billion, which do not have an expiration date, and cumulative state NOL carryforwards of $5.3 billion for financial statement purposes.

NRG also has cumulative foreign NOL carryforwards of $382 million, most of which have no expiration date.

In addition to the above NOLs, NRG has a $270 million indefinite carryforward for interest deductions, as well as $393 million of tax credits to be utilized in future years.

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The following table presents the summarized statement of operations:

(In millions) For the Year Ended December 31, 2021 (a)

Operating revenues $ 23,679

Operating income 3,753

(In millions) For the Year Ended December 31, 2022

Operating income (b)

Total other expense (322)

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Net Income 1,247

(a) Intercompany transactions with Non-Guarantors include operating revenue of $42 million, cost of operations of $(235) million and selling, general and administrative of $108 million

(a) Intercompany transactions with Non-Guarantors include revenue of $24 million during the year ended December 31, 2022

(b) Intercompany transactions with Non-Guarantors including cost of operations of $(375) million and selling, general and administrative of $204 million during the year ended December 31, 2022

The following table presents the summarized balance sheet information:

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Non-current assets 13,132

Current liabilities (a)

Current liabilities (b)

Non-current liabilities 11,860

(a) Includes intercompany receivables of $86 million and intercompany payables of $50 million due from Non-Guarantors

(a) Includes intercompany receivables due from Non-Guarantors of $30 million as of December 31, 2022

(b) Includes intercompany payables due to Non-Guarantors of $96 million as of December 31, 2022

Fair Value of Derivative Instruments

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These contracts are recognized on the balance sheet at fair value and changes in the fair value of these derivative financial instruments are recognized in earnings.

The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820, Fair Value Measurements and Disclosures , or ASC 820.

Specifically, these tables disaggregate realized and unrealized changes in fair value;

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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 (Losses)/Gains (In millions)

Derivative Activity Gains/(Losses) (In millions)

Fair value of contracts as of December 31, 2021 $ 2,341

Contracts realized or otherwise settled during the period (1,225)

Contracts acquired from Direct Energy (283)

Changes in fair value 2,437

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As of December 31, 2022, NRG's net derivative asset was $3.6 billion, an increase to total fair value of $1.2 billion as compared to December 31, 2021.

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

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

Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in an increase of approximately $1.4 billion in the net value of derivatives as of December 31, 2022.

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Derivative Instruments Assumptions used in valuation techniques

Assumptions used in forecasting generation and retail load

Market maturity and economic conditions

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Income Taxes and Valuation Allowance for Deferred Tax Assets

Ability to be sustained upon audit examination of taxing authorities

Interpret existing tax statute and regulations upon application to transactions

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

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

Regulatory and political environments and requirements

Evaluation of Assets for Impairment Regulatory and political environments and requirements

Estimated useful lives of assets

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Derivative Instruments

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

The Company follows the guidance of ASC 815, Derivatives and Hedging "(A SC 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.

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These estimations are considered to be critical accounting estimates.

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

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

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

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

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

The Company continues to maintain a valuation allowance of approximately $248 million as of December 31, 2021 against deferred tax assets consisting of state net operating losses and foreign NOL carryforwards in jurisdictions where the Company does not currently believe that the realization of deferred tax assets is more likely than not.

The Company continues to maintain a valuation allowance of $224 million as of December 31, 2022 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, 2021, the Company's valuation allowance balance was $248 million.

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federal income tax examinations for years prior to 2019.

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, the Company evaluates property, plant and equipment and certain intangible assets for impairment whenever indicators of impairment exist.

With few exceptions, state and Canadian income tax examinations are no longer open for years before 2014.

NRG does not intend, nor currently foresee a need, to repatriate funds held at its international operations into the U.S.

These funds are deemed to be indefinitely reinvested in its 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

In accordance with ASC 360, Property, Plant, and Equipment (" 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:

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Assets held-for-sale are reported at the lower of the carrying amount or fair value less the cost to sell.

The estimation of fair value, whether in conjunction with an asset to be held and used or with an asset held-for-sale, and the evaluation of asset impairment are, by their nature, subjective.

The estimation of fair value, whether in conjunction with an asset to be held and used or with an asset held-for-sale, and the evaluation of asset impairment are, by

their nature, subjective.

The Company considers quoted market prices in active markets to the extent they are available.

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Actual future market prices and project costs could vary from those used in NRG's estimates and the impact of such variations could be material.

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

The Company considered the decline in PJM capacity prices and the near-term retirement dates of certain assets to be a trigger for impairment and performed impairment tests on the PJM generating assets and the goodwill associated with Midwest Generation.

The Company measured the impairment losses on the PJM generation assets and Midwest Generation goodwill as the difference between the carrying amount and the fair value of the PJM generating assets and Midwest Generation reporting unit, respectively.

Fair values were determined primarily using an income approach in which the Company applied a discounted cash flow methodology to the long-term budgets for the plants and reporting unit.

Significant inputs impacting the income approach include the Company's long-term view of capacity and fuel prices, projected generation, the physical and economic characteristics of each plant, and the discount rate applied to the after-tax cash flow projections.

Impairment losses of $271 million and $35 million were recorded in the East segment on the PJM generating assets and Midwest Generation goodwill, respectively.

Annually, during the fourth quarter, the Company revises its views of power and fuel prices including the Company's fundamental view for long-term prices, forecasted generation and operating and capital expenditures, in connection with the preparation of its annual budget.

Changes to the Company's views of long-term power and fuel prices impact the Company’s projections of profitability, based on management's estimate of supply and demand within the sub-markets for its operations and the physical and economic characteristics of each of its businesses.

In the fourth quarter of 2021, the Company recognized an impairment loss of $213 million in the East segment as a result of changes in the long-term outlook of the Joliet facility prompted by market conditions and an assessment of various alternatives for the long-term operational landscape of the facility including the impact of the CEJA in Illinois, which concluded with the annual budget process.

The Company recorded additional impairment losses of $16 million and $9 million related to various power plants in the East and West/Services/Other segments, respectively.

In the third quarter of 2020, the Company concluded its Home Solar business was held for sale as a result of advanced negotiations to sell the business and recorded an impairment loss of $29 million in the West/Services/Other segment to adjust the carrying amount of the assets and liabilities to fair market value based on indicative sale prices.

On November 13, 2020, the Company completed the sale of the Home Solar business for $66 million.

In the fourth quarter of 2020, the Company recognized an impairment loss of $32 million in the West/Services/Other segment related to the Cottonwood facility.

The impairment was attributable to the Company's long-term services agreement and related lease payments, as the carrying amounts of the assets from the contract were higher than the estimated operating cash flow though the remaining lease period.

Additionally, in the fourth quarter of 2020, the Company recorded $14 million of impairment losses related to intangible assets in the Texas segment.

Equity Method Investments

The Company is also required to evaluate for impairment its equity method investments in accordance with ASC 323, Investments - Equity Method and Joint Ventures , or ASC 323.

The standard for determining whether an impairment must be recorded under ASC 323 is whether an observed decline in the value of an equity method investment is considered other-than-temporary.

The evaluation and measurement of impairments under ASC 323 involves the same uncertainties as described for long-lived assets that the Company owns directly and accounts for in accordance with ASC 360.

Similarly, the estimates that the Company makes with respect to its equity method investments are subjective, and the impact of variations in these estimates could be material.

Additionally, if the projects in which the Company holds these investments recognize an impairment under the provisions of ASC 360, the Company would record its proportionate share of that impairment loss and would evaluate its investment for an other-than-temporary decline in value under ASC 323.

During the first quarter of 2020, NRG recorded an impairment loss of $18 million in the Texas segment, attributable to its equity method investment in Petra Nova Parish Holdings, which included the anticipated drawdown of the $12 million letter of credit posted in September 2019 to cover certain project debt reserve requirements.

For further discussion, see Item 15 —Note 11 , Asset Impairments .

Goodwill and Other Intangible Assets

At December 31, 2021, the Company reported goodwill of $1.8 billion, consisting of $1.3 billion from the acquisition of Direct Energy in 2021, $130 million associated with the acquisition of Midwest Generation and $414 million for retail operations acquisitions, including Stream Energy, which was acquired in 2019.

The Company applies ASC 805, Business Combinations , or ASC 805, and ASC 350, Intangibles-Goodwill and Other, or ASC 350 to account for its goodwill and intangible assets.

At December 31, 2022, the Company reported goodwill of $1.7 billion, consisting of $1.2 billion from the acquisition of Direct Energy in 2021 and $408 million for retail operations acquisitions, including Stream Energy, which was acquired in 2019.

The Company applies ASC 805, Business Combinations ("ASC 805"), and ASC 350, Intangibles-Goodwill and Other (" 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.

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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.

During the fourth quarter of 2021, the Company also performed a quantitative assessment for the Midwest Generation (East segment) and West/Services/Other reporting units.

The Company determined the fair value of the reporting units using an income approach.

Based on the income approach, the Company estimated the fair value of each reporting units' cash flows exceeded its carrying value and, as such, NRG concluded that the goodwill associated with each reporting unit was not impaired as of December 31, 2021.

The Company believes the methodology and assumptions used in its quantitative assessments were consistent with the views of market participants.

Significant inputs to the determinations of fair value of the Midwest Generation reporting unit were as follows:

• The Company applied a discounted cash flow methodology to the long-term budgets for the Midwest Generation plants, resulting in fair value over the carrying value of the reporting unit of 117%.

The significant assumptions used to derive the long-term budgets used in the income approach are affected by the following key inputs:

◦ The Company's views of power, capacity and fuel prices consider market prices for the next five years and the Company's fundamental view for the longer term, driven by the Company's long-term view of the price of natural gas.

The Company's fundamental view for the longer term reflects the implied prices and heat rate that would support new build of a combined cycle gas plant.

The price of natural gas plays an important role in setting the price of electricity in many of the regions where NRG operates power plants.

Hedging is included to the extent of contracts already in place;

◦ The Company's estimate of generation, fuel costs, capital expenditure requirements and the existing and anticipated impact of environmental regulations;

◦ The Company's fundamental view for the longer term, cash flows for the plants in the region were included in the fair value calculation through the end of each plants' estimated useful life;

◦ Projected generation and resulting energy gross margin in the long-term budgets is based on an hourly dispatch that simulates dispatch of each unit into the power market.

The dispatch simulation is based on power prices, fuel prices, and the physical and economic characteristics of each plant.

Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors.

As a result, there can be no assurance that the estimates and assumptions made for purposes of the annual goodwill impairment test will prove to be accurate predictions of the future.

For further discussion, see Evaluation of Assets for Impairment caption above, and Item 15 —Note 11 , Asset Impairments .

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.

NRG accounts for business acquisitions using the acquisition method of accounting prescribed under ASC 805.

Under this method, the Company is required to record on its 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.

Fair value is determined 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 fair value of trade names and customer relationships are 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.

In measuring the fair value of derivative contracts for Direct Energy, 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.

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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

In addition, the Company

applied a credit reserve to reflect credit risk.

NRG describes in detail its acquisitions in Item 15 — Note 4, Acquisitions and Dispositions , to the Consolidated Financial Statements

Contingencies

6 unchanged sentences

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis