What changed in this filing

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Item 1. Business

2022-02-24 compared with 2021-03-01 · 307 added, 322 removed, 272 unchanged (70% of the section changed)

Item 1 — Business

NRG Energy, Inc., or NRG or the Company, is an integrated power company built on dynamic retail brands with diverse generation assets.

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

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

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

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

NRG is a customer-centric business focused on perfecting the integrated model by balancing retail load with generation supply within its deregulated markets.

As of December 31, 2020, the Company sold energy, services, and innovative, sustainable products and services directly to retail customers under the brand names NRG, Reliant, Green Mountain Energy, Stream, and XOOM Energy, as well as other brand names owned by NRG, supported by approximately 23,000 MW of generation.

NRG also conducts business under the brand name of Direct Energy as a result of the Company's acquisition of Direct Energy, a North American subsidiary of Centrica plc, on January 5, 2021.

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

states and 8 Canadian provinces.

In addition, Direct Energy is a participant in the wholesale gas and power markets in the United States and Canada.

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

On February 28, 2021, the Company entered into a definitive purchase agreement with Generation Bridge, an affiliate of ArcLight Capital Partners, to sell approximately 4,850 MWs of fossil generating assets from its East and West regions of operations for total proceeds of $760 million, subject to standard purchase price adjustments and certain other indemnifications.

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

The transaction is expected to close in the fourth quarter of 2021, and is subject to various closing conditions, approvals and consents, including FERC, NYSPSC, and antitrust review under Hart-Scott-Rodino.

The Company has achieved the targets related to operations and cost excellence, portfolio optimization, and capital structure and allocation enhancement, as set out by the Transformation Plan.

See Item 7 - Management's Discussion and Analysis of Financial Conditions and Results of Operations for further discussion.

NRG's strategy is to maximize stakeholder value through the safe production and sale of reliable power and gas to its customers in the markets it serves, while positioning the Company to provide innovative solutions to the end-use energy customer.

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

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

NRG sold 157 TWhs of electricity and 1,877 MMDth of natural gas in 2021, making it one of the largest competitive energy retailers in the U.S.

As of the end of 2021, NRG had recurring electricity and/or natural gas sales in 24 U.S.

states, the District of Columbia, and 8 provinces in Canada.

NRG's retail brands, collectively, have the largest share of competitively served residential electric customers in Texas and nationwide.

The following chart represents NRG's sales volumes for the year ended December 31, 2021:

NRG's strategy is to maximize stakeholder value through the safe production and sale of reliable electricity and natural gas to its customers in the markets it serves, while positioning the Company to provide innovative solutions to the end-use energy or service customer.

This strategy is intended to enable the Company to optimize its integrated model to generate stable and predictable cash flow, significantly strengthen earnings and cost competitiveness, and lower risk and volatility.

Sustainability is a philosophy that underpins and facilitates value creation across our business for our stakeholders.

It is an integral piece of NRG's strategy and ties directly to business success, reduced risks and enhanced reputation.

To effectuate the Company’s strategy, NRG is focused on:

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(ii) offering a variety of energy products and services, including renewable energy solutions, that are differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs;

(iii) excellence in operating performance of its existing assets;

(iv) optimal hedging of NRG's portfolio;

(iii) excellence in operating performance of its assets;

(iv) optimal hedging of its portfolio;

and (v) engaging in disciplined and transparent capital allocation.

Sustainability is an integral piece of NRG's strategy and ties directly to business success, reduced risks and brand value.

In 2019, NRG announced the acceleration of its science-based GHG emissions reduction goals to align with prevailing climate science, limiting global warming in the post-industrial era to 1.5 degree Celsius.

Under its new GHG emissions reduction timeline, NRG is targeting a 50% reduction by 2025, from its current 2014 baseline, and net-zero emissions by 2050.

The Company is on track to meet its 2025 goal.

The 2021 fiscal year was pivotal for the Company.

NRG completed the acquisition of Direct Energy, doubling the size of its retail portfolio, while further decreasing its physical generation through the sale and planned retirement of certain assets, each as further discussed below.

The completion of these significant activities positioned NRG for the next phase of its strategy focusing on growth.

The Company implemented a four-year plan beginning in 2022 to invest up to $2 billion in order to achieve growth through optimization of the Company's core power and natural gas sales, as well as integrated solution sales within its core network in both power and home services.

Significant Acquisitions, Dispositions and Announced Retirements

On January 5, 2021, the Company acquired Direct Energy.

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

states and 8 Canadian provinces.

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

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

NRG realized its planned synergy target of $175 million in 2021 and expects to realize annual synergies of $225 million and $300 million in 2022 and 2023, respectively.

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

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

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

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

During the second quarter of 2021, the results of the PJM Base Residual Auction for the 2022/2023 delivery year were released, leading the Company to announce the near-term retirement of approximately 1,600 MW of its PJM coal generating assets in June 2022.

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

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

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

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

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

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

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

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

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

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

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

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

Business Overview

The Company’s core business is the sale of electricity and natural gas to residential, commercial and industrial customers, supported by the Company's wholesale generation.

As part of perfecting the integrated model, in which the majority of the Company’s generation serves its retail customers, the Company began managing its operations based on the combined results of the retail and wholesale generation businesses with a geographical focus in 2020.

As a result, the Company changed its business segments from Retail and Generation to Texas, East and West/Other beginning in the first quarter of 2020.

The Company's updated segment structure reflects how management makes financial decisions and allocates resources.

The Company's business is segregated as follows:

The Company’s core business is the sale of electricity and natural gas to residential, commercial and industrial and wholesale customers, supported by the Company's wholesale generation.

NRG manages its operations based on the combined results of the retail and wholesale generation businesses with a geographical focus.

The Company's business is segmented as follows:

• Texas, which includes all activity related to customer, plant and market operations in Texas;

• East, which includes the remaining activity related to customer operations and all activity related to plant and market operations in the East;

• West/Other, which includes the following assets and activities:

(i) all activity related to plant and market operations in the West, (ii) activity related to the Cottonwood power plant that was sold to Cleco on February 4, 2019 and is being leased back until 2025, (iii) the remaining renewables activity, including the Company’s equity method investments in Ivanpah Master Holdings, LLC and Agua Caliente (which was sold on February 3, 2021) and the NFL stadium solar generating assets, and (iv) activity related to the Company’s equity method investment for the Gladstone power plant in Australia;

• East, which includes all activity related to customer, plant and market operations in the East;

• West/Services/Other, which primarily includes the following assets and activities:

(i) all activity related to customer, plant and market operations in the West and Canada, (ii) the services businesses, (iii) activity related to the Cottonwood facility, (iv) the remaining renewables activity, including the Company’s equity method investment in Ivanpah Master Holdings, LLC, and (v) activity related to the Company’s equity method investment for the Gladstone power plant in Australia;

• Corporate activities.

As of December 31, 2020, the vast majority of the Company’s business was in Texas, where the Company’s generation supply is fully integrated with its retail load.

As of December 31, 2021, in Texas, the Company’s generation supply is fully integrated with its retail load.

In the East, the Company’s retail load is more dispersed throughout the region and not fully integrated with the Company’s generation supply due to the locations of its power plants in that region.

In the West, the Company’s business is primarily generation supply.

The acquisition of Direct Energy broadens the Company's presence in the Northeast and into states and locales where it did not previously operate, supporting NRG's objective to diversify its business.

The acquired operations of Direct Energy will be integrated into the existing NRG segment structure.

Domestic customer and market operations will be combined into the corresponding geographical segments of Texas, East and West/Other.

The East segment will also include the deregulated customer and market operations of Canada.

The West/Other segment will also include activity related to the regulated operations in Alberta, Canada and the services businesses.

In the West/Services/Other, the Company’s business is primarily serving retail load and services customers.

The Company’s integrated model consists of three core functions:

Customer Operations, Market Operations and Plant Operations, which directly support each other in each geographic region.

The Company’s integrated model provides the advantage of being able to supply the Company’s retail customers with electricity from the Company’s assets, which reduces the need to sell electricity to and buy electricity from other institutions and intermediaries, resulting in stable earnings and cash flows, lower transaction costs and less credit exposure.

The integrated model also results in a reduction in actual and contingent collateral through offsetting transactions, thereby minimizing transactions with third parties.

NRG provides energy and related services to residential, industrial and commercial, and wholesale customers at either fixed, indexed or month-to-month prices through various brands and sales channels across the U.S.

Residential and small commercial ("Mass market") customers typically contract for terms ranging from one month to five years, while industrial and large commercial ("C&I") contracts are often between one year and five years in length.

NRG sold approximately 68.2 TWhs of electricity and 23.5 MMDth of natural gas in 2020 and served approximately 3.6 million customers as of December 31, 2020, making it one of the largest competitive energy retailers in the U.S.

In any given year, the quantity of TWhs and MMDth sold can be affected by weather, economic conditions and competition.

As of the end of 2020, NRG had recurring electricity and/or natural gas sales in 19 U.S.

states, the District of Columbia, and 2 provinces in Canada.

Following the acquisition of Direct Energy, NRG has recurring electricity and/or natural gas sales in 24 U.S.

states, the District of Columbia, and 8 provinces in Canada.

NRG's retail brands, collectively, have the largest share of competitively served residential electric customers in Texas and nationwide.

The charts below illustrate NRG's U.S.

retail capabilities, power generation and net capacity as of and for the year ended December 31, 2020:

Extreme Weather Event in Texas During February 2021

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

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

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

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

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

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

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

In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the COVID-19 outbreak a national emergency.

Electricity was deemed a ‘critical and essential business operation’ under various state and federal governmental COVID-19 mandates.

NRG has been and continues to remain focused on protecting the health and well-being of its employees, while supporting its customers and the communities in which it operates and assuring the continuity of its operations.

During 2020, NRG contributed $2 million to COVID-19 relief efforts, including funding for urgently needed safety equipment supporting first responders, as well as funds that aided local communities and teachers.

The Company also allocated funding to the NRG Employee Relief Fund to assist employees adversely impacted by natural disasters and other extraordinary events.

NRG activated its Crisis Management Team ("CMT") in January 2020, which proactively began managing the Company's response to the impacts of COVID-19.

The CMT implemented the business continuity plans for the Company and had taken a variety of measures to ensure the ongoing availability of the Company's services, while maintaining the Company's commitment to its core values of health and safety.

Pursuant to the Company's Infectious Disease & Pandemic Policy, in March 2020, NRG implemented restrictions on business travel and face-to-face sales channels, instituted remote work practices and enhanced cleaning and hygiene protocols in all of its offices and facilities.

In order to effectively serve the Company’s customers, select essential employees and contractors continued to report to plant and certain office locations.

In June 2020, summer-critical office employees also returned to the offices.

The Company requires pre-entry screening, including temperature checks, separation of work crews, additional personal protective equipment for employees and contractors when social distancing cannot be maintained, and a ban on all non-essential visitors.

As a result of these business continuity measures, the Company has not experienced any material disruptions in its ability to continue its business operations to date.

The first COVID-19 vaccine became available in the United States in December 2020.

NRG continues to advocate alongside state and federal trade groups for the high prioritization of essential electric industry personnel for inoculation against COVID-19.

States are receiving weekly doses of vaccines and allocating those doses to frontline healthcare workers, elderly populations and high risk individuals.

NRG continues to monitor state information as well as dosage and allocation numbers to anticipate the latest timing of vaccine distribution to our essential employees.

The Company will continue to evaluate additional return to normal work operations on a location-by-location basis as COVID-19 conditions evolve.

The Company continues to utilize the communication protocol established in January 2020, including a central information hub on its intranet.

The Company has provided additional wellness programs to support employees through the pandemic, including no-cost access to telehealth services, a mindfulness and meditation program, center or home-based backup child and elder care, and access to the Company's Emergency Relief Fund for financially impacted employees.

Following the President's declaration of COVID-19 outbreak as a national emergency in March 2020, the Governors of the majority of states in which the Company operates issued executive orders that every person should, except where necessary to provide or obtain essential services, minimize social gatherings and minimize in-person contact with people who are not in the same household.

The impact of these orders affected energy loads due to closed schools, restaurants and bars, except in certain cases for takeout, and other non-essential businesses.

As state restrictions have been eased or lifted, loads have begun to recover in those markets in which the Company operates.

The rebound in demand has varied across the Company's market footprint, as restrictions vary regionally.

During 2020, the Company experienced increased demand from its residential portfolio as many people remained at home, while the load for small businesses and C&I customers decreased due to reduced economic activity.

The Company expects similar demand trends to continue in the near future.

These restrictions have also created limitations to the Company's face-to-face sales channels and are expected to negatively impact the Company's customer count primarily in the East region.

As the COVID-19 vaccine is distributed and the spread of transmission decreases, the Company would anticipate changes to the previously disclosed restrictions.

In Texas, the PUCT adopted the COVID-19 Electricity Relief Program (“ERP”) to mitigate the impact of COVID-19 on Texas retail electric customers experiencing economic hardship as a result of the pandemic.

The COVID-19 ERP provided temporary disconnection protection for eligible customers and established funds to offset some of the costs incurred by retail electric providers that continued service to those customers.

The COVID-19 ERP disconnection protection and benefits ended on September 30, 2020.

Consistent with the PUCT's orders, NRG is continuing to offer deferred payment plans to all residential and small commercial customers while the declaration of emergency in Texas is in place.

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

NRG believes it has sufficient liquidity on hand to continue business operations in light of current circumstances posed by the pandemic.

As disclosed in the Liquidity and Capital Resources section, the Company has total available liquidity of $7.0 billion as of December 31, 2020, consisting of cash on hand, its Revolving Credit Facility and additional facilities.

The situation surrounding COVID-19 remains fluid and the potential for a material adverse impact on the Company exists as long as the virus impacts the level of economic activity in the United States and abroad.

The Company expects the risk to decrease in the future as vaccinations are administered.

NRG cannot reasonably estimate with any degree of certainty the full impact COVID-19, and any resurgence of COVID-19, may have on the Company’s future results of operations, financial position, and liquidity.

The extent to which the COVID-19 pandemic may impact the Company’s business, operating results, financial condition, risk exposure or liquidity will depend on future developments, including the duration of the pandemic, travel restrictions, business and workforce disruptions, any resurgence of the pandemic and the effectiveness of actions taken to contain, mitigate and treat the disease.

See Part I, Item 1A — Risk Factors of this Form 10-K.

The Company’s integrated model in Texas provides the advantage of being able to supply a significant portion of the Company’s retail customers with electricity from the Company’s assets, which reduces the need to sell electricity to and buy electricity from other institutions and intermediaries, resulting in stable earnings and cash flows, lower transaction costs and less credit exposure.

The integrated model also results in a reduction in actual and contingent collateral through offsetting transactions, thereby reducing transactions with third parties.

Customer Operations

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Customer portfolio maintenance and retention activities include fulfillment, billing, payment processing, collections, customer service, issue resolution, and contract renewals.

Throughout all Customer Operations activities, the customer experience is kept at the forefront to inform decision-making and optimize retention, while creating supporters and advocates for NRG’s brands in the

NRG provides energy and related services at either fixed, indexed or month-to-month prices.

Home customers typically contract for terms ranging from one month to five years, while Business contracts are often between one year and five years in length.

Following the expansion of the customer base with the acquisition of Direct Energy, Customer Operations now comprises three end-use customer facing teams:

NRG Home, which serves Mass Market customers, NRG Business, which serves medium and large business customers, and NRG Services, which primarily includes the services businesses acquired.

NRG Home, which serves residential customers, NRG Business, which serves business customers, and NRG Services, which primarily includes the services businesses acquired.

Product Offerings

NRG sells a variety of products to residential and small commercial customers, including retail electricity and energy management, natural gas, home security, line and surge protection products, HVAC installation, repair and maintenance, home warranty and protection products, carbon offsets, back-up power stations, portable power, portable solar and portable lighting.

Mass market customers make purchase decisions based on a variety of factors, including price, incentive, customer service, brand, innovative offers/features and referrals from friends and family.

NRG sells a variety of products to residential and small commercial customers, including retail electricity and energy management, natural gas, home security, line and surge protection products, HVAC installation, repair and maintenance, home protection products, carbon offsets, back-up power stations, portable power, portable solar and portable lighting.

Home and Services customers make purchase decisions based on a variety of factors, including price, incentive, customer service, brand, innovative offers/features and referrals from friends and family.

Through its broad range of service offerings and value propositions, NRG is able to attract, retain, and increase the value of its customer relationships.

NRG's brands are recognized for exemplary customer service, innovative smart energy and technology product offerings, and environmentally-friendly solutions.

The Company provides power and natural gas to the business-to-business markets in North America, as well as retail services, including demand response, commodity sales, energy efficiency and energy management solutions to C&I customers.

The Company is an integrated provider of supply and distributed energy resources and focuses on distributed products and services as businesses seek greater reliability, cleaner power and/or other benefits that they cannot obtain from the grid.

The Company is an integrated provider of supply and distributed energy resources and focuses on distributed products and services as businesses seek greater reliability, cleaner power and other benefits that they cannot obtain from the grid.

These solutions include system power, distributed generation, renewable products, carbon management and specialty services, backup generation, storage and distributed solar, demand response, and energy efficiency and advisory services.

In providing on-site energy solutions, the Company often benefits from its ability to supply energy products from its wholesale generation portfolio to C&I customers.

In 2020, the Company sold approximately 20 TWhs of electricity to C&I customers and managed approximately 1,750 MWs of demand response positions across its portfolio.

In providing on-site energy solutions, the Company often benefits from its ability to supply energy products from its wholesale generation portfolio to Business customers.

Market Operations

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These objectives are intended to reduce supply costs and maximize earnings with predictable cash flows.

To meet these objectives, NRG enters into supply, power and gas sales and hedging arrangements via a wide range of products and contracts, including (i) renewable PPAs, (ii) capacity auctions and other contracted revenue sources, (iii) fuel supply and transportation contracts, and (iv) physical and financial natural gas derivative instruments and other financial instruments.

Power and natural gas are the two main commercial groups within market operations.

The power commercial group is responsible for end-use electricity supply including power plant optimization and certain fuel supply.

To meet the market operations objectives, NRG enters into supply, power and gas sales and hedging agreements via a wide range of products and contracts, including (i) physical and financial commodity instruments, (ii) fuel supply and transportation contracts, (iii) renewable PPAs and (iv) capacity and other contracted revenue sources, as further discussed below.

In addition, because changes in power prices in the markets where NRG operates are generally correlated to changes in natural gas prices, NRG uses hedging strategies that may include power and natural gas forward purchases and sales contracts to manage the commodity price risk.

Renewable PPAs

During 2019, NRG began procuring mid to long-term renewable generation through power purchase agreements.

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

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

The Company expects to continue evaluating and executing agreements, such as these, that support the needs of the business.

Capacity and Other Contracted Revenue Sources

NRG's revenues and cash flows, primarily in the East and West, benefit from capacity/demand payments and other contracted revenue sources, originating from market clearing capacity prices, resource adequacy contracts, tolling arrangements and other long-term contractual arrangements.

The Company's largest sources of capacity revenues are capacity auctions in PJM, ISO-NE and NYISO.

Both PJM and ISO-NE operate a pay-for-performance model where capacity payments are modified based on real-time performance and NRG's actual revenues will be the combination of revenues based on the cleared auction MWs plus the net of any over- and under-performance of NRG's respective generation assets.

The Company primarily sells physical and financial capacity forward through bilateral contracts for our New York state assets.

To the extent NRG is not able to enter into physical bilateral contracts, NRG will sell the remaining capacity into the NYISO six month strip, monthly or spot auctions.

• 2024/2025 ISO-NE Auction Results - On February 11, 2020 ISO-NE announced the results of its 2024/2025 forward capacity auction.

NRG cleared 1,518 MW of capacity.

NRG's expected capacity revenues from the auction for the 2024/2025 delivery year are approximately $48 million.

• PJM Auction Results — PJM announced during 2019 it was suspending all auction deadlines relating to Base Residual Auctions for 2022/2023 and 2023/2024 delivery year, consistent with FERC’s July 25, 2019 Order.

The auctions are now set to resume in 2021.

Refer to the Capacity Market Reforms Filing discussion within the Regional Regulatory Developments section below for further discussion.

In California, there is a resource adequacy requirement that is primarily satisfied through bilateral contracts.

Such bilateral contracts are typically short-term resource adequacy contracts.

When bilateral contracting does not satisfy the resource adequacy need, such shortfalls can be addressed through procurement tools administered by the CAISO, including the capacity procurement mechanism or reliability must-run contracts.

Fuel Supply and Transportation

Physical and Financial Commodity Instruments

NRG trades electric power, natural gas and related commodities, environmental products, weather products and financial products, including forwards, futures, options and swaps.

NRG enters into these instruments primarily to manage price and delivery risk, optimize physical and contractual assets in the portfolio, manage working capital requirements, reduce the carbon exposure in its business and comply with laws.

Fuel Supply and Transportation Contracts

NRG's fuel requirements consist of various forms of fossil fuel and nuclear fuel.

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NRG's primary fuel requirements consist of the following:

Natural Gas — NRG operates a fleet of mid-merit and peaking natural gas plants across all its U.S.

wholesale regions.

Fuel needs are managed on a spot basis, especially for peaking assets, as the Company does not believe it is prudent to forward purchase natural gas for these types of units as the dispatch is highly unpredictable.

The Company contracts for natural gas storage services, as well as natural gas transportation services to deliver natural gas when needed.

Coal — The Company believes it is adequately hedged, using forward coal supply agreements, for its domestic coal consumption for 2021.

NRG actively manages its coal requirements based on forecasted generation, market volatility and its inventory on site.

Natural Gas — NRG operates a fleet of mid-merit and peaking natural gas plants.

Fuel needs are managed by the natural gas commercial group, on a spot basis, especially for peaking assets, as the Company does not believe it is prudent to forward purchase natural gas for these types of units as the dispatch is highly unpredictable.

Coal —NRG actively manages its coal requirements based on forecasted generation, market volatility and its inventory on site.

The Company believes it is adequately hedged, using forward coal supply agreements, for its domestic coal consumption for 2022.

As of December 31, 2021, NRG had purchased forward contracts to provide fuel for approximately 88% of the Company's expected requirements for 2022 and 2023.

NRG purchased approximately 11 million tons of coal in 2020, almost all of which was Powder River Basin coal.

For fuel transport, NRG has entered into various rail transportation and rail car lease agreements with varying tenures that will provide for most of the Company's transportation requirements of Powder River Basin coal for the next 2 years.

For the domestic fleet, NRG purchased approximately 16.1 million tons of coal in 2021, almost all of which was Powder River Basin coal.

For fuel transport, NRG has entered into various rail transportation and rail car lease agreements with varying tenors that will provide for most of the Company's transportation requirements of Powder River Basin coal for the next three years.

Nuclear Fuel — STP's owners, including NRG, satisfy their fuel supply requirements by:

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and (iii) contracting for fabrication of nuclear fuel assemblies.

Through its proportionate participation in STPNOC, which is the NRC-licensed operator of STP that is responsible for all aspects of fuel procurement, NRG is party to a number of long-term forward purchase contracts with many of the world's largest suppliers covering STP's requirements for uranium concentrates with only approximately 25% of STP's requirements outstanding for the duration of the original operating license.

Similarly, NRG is party to long-term contracts to procure STP's requirements for conversion and enrichment services and fuel fabrication for the life of the operating license.

Since the operating license was renewed for another 20 years in 2017, STPNOC has begun to review a second phase of fuel purchasing.

Derivative Instruments and Other Financial Instruments

NRG also trades electric power, natural gas and related commodities, environmental products, weather products and financial products, including forwards, futures, options and swaps.

NRG enters into these instruments for many reasons, including to manage price and delivery risk, optimize physical and contractual assets in the portfolio, manage working capital requirements, reduce the carbon exposure in its business and comply with regulations and laws.

Similarly, STP has begun the process of covering fuel supply requirements into the extended license period and has secured a fabrication contract with Westinghouse through 2047/2048.

Other fuel requirements such as uranium, conversion and enrichment remain open at this time.

Renewable PPAs

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

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

The average tenor of these agreements is twelve years.

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

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

Capacity and Other Contracted Revenue Sources

The Company's largest sources of continuing capacity revenues are capacity auctions in PJM and NYISO.

PJM operates a pay-for-performance model where capacity payments are modified based on real-time performance and NRG's actual revenues will be the combination of revenues based on the cleared auction MW plus the net of any over- and under-performance of NRG's respective generation assets.

The Company primarily sells physical and financial capacity forward through bilateral contracts for our New York state assets.

To the extent NRG is not able to enter into physical bilateral contracts, NRG will sell the remaining capacity into the NYISO six-month strip, monthly or spot auctions.

In California, there is a resource adequacy requirement that is primarily satisfied through bilateral contracts.

Such bilateral contracts are typically short-term resource adequacy contracts.

The natural gas commercial group is responsible for all costing, logistics and supply for all of NRG's residential, commercial & industrial and wholesale customers.

The Direct Energy acquisition, which closed on January 5, 2021, significantly increased our capabilities and scale across the natural gas value chain.

NRG has acquired contractual rights to natural gas transportation and storage assets across its footprint that allow for optimal supply economics in support of our various businesses.

Our diversified load coupled with this asset portfolio enables us to deliver supply economically while providing incremental optimization activities when market conditions allow.

The scale of the natural gas operation extends from the wellhead (through our producer services business) to our end use customers (through our various sales channels).

This scale, coupled with our associated assets, gas system platform and people, create significant opportunity across North America.

Plant Operations

The Company owns a diversified power generation portfolio with approximately 23,000 MW of fossil fuel, nuclear and renewable generation capacity at 33 plants as of December 31, 2020.

The Company's power generation assets are diversified by fuel-type, dispatch level and region, which helps mitigate the risks associated with fuel price volatility and market demand cycles.

The Company owns and leases a diversified wholesale generation portfolio with approximately 18,000 MW of fossil fuel, nuclear and renewable generation capacity at 25 plants as of December 31, 2021, including approximately 1,600 MW of its PJM coal fleet with an announced retirement date of June 2022.

The Company's wholesale generation assets are diversified by fuel-type and dispatch level, which helps mitigate the risks associated with fuel price volatility and market demand cycles.

NRG continually evaluates its generation portfolio to focus on asset optimization opportunities and the locational value of its generation assets in each of the markets where the Company participates, as well as opportunities for the development of new generation.

The following table summarizes NRG's generation portfolio as of December 31, 2021:

West/Services/Other

Natural gas 4,775 1,881 1,494 8,150

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Utility Scale Solar — — 219 219

Battery Storage (b)

Battery Storage 2 — — 2

Total generation capacity 10,083 5,476 2,318 17,877

(a) All Utility Scale Solar are described in MW on an alternating current basis.

MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units

(b) The Distributed Solar figure includes the aggregate production capacity of installed and activated residential solar energy systems

MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest.

Plant Operations is responsible for operating the Company's generation facilities at the highest standards of safety and reliability, and includes (i) operations and maintenance, (ii) asset management, and (iii) development, engineering and construction.

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The Company evaluates capital projects required for continued operation and strategic enhancement of the assets, provides quality assurance on capital outlays, and assesses the impact of rules, regulations, and laws on business profitability.

In addition, the Company manages its long-term contracts, power purchase agreements, and real estate holdings and provides third party asset management services.

In addition, the Company manages its long-term contracts, PPAs, and real estate holdings and provides third party asset management services.

Development, Engineering & Construction

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Operational Statistics

The following statistics represent the Company's retail customer count, load and contract mix:

Years ended December 31,

The following statistics represent the Company's retail load and customer count:

Year ended December 31,

2021 2020 2019

Sales volumes (in GWh)

Mass Market electricity - Texas 38,473 38,958 37,846

Mass Market electricity - East 10,221 9,918 7,968

C&I electricity - Texas 17,928 18,976 20,192

C&I electricity - East 1,596 1,214 984

Sales volumes - Electricity (in GWh)

Home - Texas 42,397 38,473 38,958

Home - East 14,108 10,221 9,918

Home - West/Services/Other 2,252 — —

Business - Texas 34,367 17,928 18,976

Business - East 53,204 1,596 1,214

Business - West/Services/Other 10,625 — —

Total Load 156,953 68,218 69,066

Customer count - Electricity (in thousands)

Mass Market - Texas (a)

Sales volumes - Natural gas (in MDth)

Home - East 74,920 23,509 23,359

Home - West/Services/Other 97,272 — —

Business - East 1,595,533 — —

Business - West/Services/Other 109,021 — —

Total Load 1,876,746 23,509 23,359

Year ended December 31,

2021 2020 2019

Customer count - Electricity customers (a)(b) (in thousands)

Average retail 3,055 2,449 2,358

Ending retail 3,024 2,451 2,450

Mass Market - East

Average retail 1,484 1,019 990

Ending retail 1,402 970 1,070

(a) Includes customers of non-electric services

Customer count - Natural gas - East (in thousands)

Average retail Mass Market 156 122 64

Ending retail Mass Market 166 158 99

Customer contract mix

Fixed 69 % 67 % 65 %

Month-to-month 23 % 24 % 25 %

Indexed 8 % 9 % 10 %

100 % 100 % 100 %

The following are industry statistics for the Company's fossil and nuclear plants, as defined by the NERC, and are more fully described below:

Home - West/Services/Other

Average retail 510 — —

Ending retail 498 — —

Customer count - Natural gas customers (b) (in thousands)

Average retail 360 156 122

Ending retail 364 166 158

Home - West/Services/Other

Average retail 452 — —

Ending retail 434 — —

Total Customer count

Average retail - Home 5,861 3,624 3,470

Ending retail - Home 5,722 3,587 3,678

(a) Includes services customers

(b) Dual fuel customers are included within electricity customer counts only

The following are industry statistics for the Company's fossil and nuclear plants, as defined by the NERC:

Annual Equivalent Availability Factor, or EAF — Measures the percentage of maximum generation available over time as the fraction of net maximum generation that could be provided over a defined period of time after all types of outages and deratings, including seasonal deratings, are taken into account.

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Net Capacity Factor — The net amount of electricity that a generating unit produces over a period of time divided by the net amount of electricity it could have produced if it had run at full power over that time period.

The net amount of electricity produced is the total amount of electricity generated minus the amount of electricity used during generation.

The tables below present these performance metrics for the Company's generation portfolio, including leased facilities and those accounted for as equity method investments, for the years ended December 31, 2020 and 2019:

The net amount of electricity produced is the total amount of electricity generated minus the amount of electricity used during generation by the station.

The tables below presents these performance metrics for the Company's generation portfolio, including leased facilities, for the years ended December 31, 2021 and 2020:

Year Ended December 31, 2021

Fossil and Nuclear Plants (a)

Capacity (MW)

Capacity (MW) (b)

Net Generation (In thousands of MWh) (a)

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East 5,476 7,494 79.8 % 11,877 8.8 %

West/Other (b)(c)

3,234 9,171 88.0 % 7,338 52.3 %

West/Services/Other 2,318 7,949 88.0 % 7,337 47.2 %

Year Ended December 31, 2020

Fossil and Nuclear Plants (a)

Capacity (MW)

Net Generation (In thousands of MWh) (a)

Capacity (MW) Net Generation (In thousands of MWh) (a)

Annual Equivalent Availability Factor Average Net Heat Rate BTU/kWh Net Capacity

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East 9,482 4,102 81.7 % 12,329 4.8 %

West/Other (b)(c)

3,294 9,462 79.9 % 6,751 51.4 %

(a) Net generation excludes equity method investments

(b) Includes the Sherbino and Guam facilities that were sold in 2019

West/Services/Other 3,234 9,171 88.0 % 7,338 52.3 %

(a) Excludes equity method investments

The generation performance by region for the three years ended December 31, 2021, 2020 and 2019 is shown below:

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Gas 1,519 1,892 2,269

Total East 4,102 6,913 10,119

Total East (b)

7,494 4,102 6,913

West/Services/Other

Gas 7,941 9,165 9,450

Renewables 8 6 12

Total West/Other 9,171 9,462 10,970

Total West/Services/Other (c)

7,949 9,171 9,462

Total generation performance 52,363 44,658 54,370

(a) Reflects the Company's undivided interest in total MWh generated by STP

(b) Includes gas generation of 855 thousand MWh, 870 thousand MWh and 903 thousand MWh and oil generation of 199 thousand MWh, 322 thousand MWh and 209 thousand MWh for the years ended December 31, 2021, 2020 and 2019, respectively, that was sold to Generation Bridge

(c) Includes gas generation of 2,445 thousand MWh, 3,002 thousand MWh, and 2,203 thousand MWh for the years ended December 31, 2021, 2020 and 2019, respectively, that was sold to Generation Bridge

While there has been consolidation in the competitive retail space over the past few years, there is still considerable competition for customers.

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Outside of Texas, electricity retailers compete with the incumbent utilities, in addition to other retail electric providers, which can inhibit competition depending on the market rules of the state.

There is a high degree of fragmentation, with both large and small competitors offering a range of value propositions, including value, rewards, and sustainability.

There is a high degree of fragmentation, with both large and small competitors offering a range of value propositions, including value, rewards, and sustainability-based offerings.

Wholesale generation is highly fragmented and diverse in terms of industry structure by region.

As such, there is a wide variation in terms of the capabilities, resources, nature and identities of the Company’s competitors depending on the market.

As such, there is wide variation in terms of the capabilities, resources, nature and identities of the Company’s competitors depending on the market.

Competitors include regulated utilities, municipalities, cooperatives, other independent power producers, and power marketers or trading companies, including those owned by financial institutions.

Seasonality and Price Volatility

The sale of electric power to retail customers is a seasonal business with the demand for power generally peaking during the summer months.

In connection with the acquisition of Direct Energy, the Company acquired a large natural gas customer portfolio, which generally experiences peak demand during the winter months.

The sale of power and natural gas to retail customers are seasonal businesses with the demand for power generally peaking during the summer, and the demand for natural gas generally peaking during the winter.

As a result, net working capital requirements for the Company's retail operations generally increase during summer and winter months along with the higher revenues, and then decline during off-peak months.

Weather may impact operating results and extreme weather conditions could have a material impact.

The rates charged to retail customers may be impacted by fluctuations in total power prices and market dynamics, such as the price of natural gas, transmission constraints, competitor actions, and changes in market heat rates.

The rates charged to retail customers may be impacted by fluctuations in total power

prices and market dynamics, such as the price of natural gas, transmission constraints, competitor actions, and changes in market heat rates.

Annual and quarterly operating results of the Company's generation portfolio can be significantly affected by weather and energy commodity price volatility.

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The attractiveness of NRG's retail offerings may be impacted by the rules, regulations, market structure and communication requirements from public utility commissions in each state and province.

NRG's fleet operates in organized energy markets, known as RTOs or ISOs.

NRG's fleet of power plants which it owns, operates or manages are located in organized energy markets, known as RTOs or ISOs.

Each organized market administers day-ahead and real-time centralized bid-based energy and ancillary services markets pursuant to tariffs approved by FERC, or in the case of ERCOT, market rules approved by the PUCT.

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The ERCOT market is one of the nation's largest and, historically, fastest growing power markets.

ERCOT is an energy-only market and has implemented market rule changes referred to as the Operating Reserve Demand Curve (ORDC) to provide pricing more reflective of higher energy value when operating reserves are scarce or constrained.

ERCOT is an energy-only market and has implemented market rule changes referred to as the ORDC to provide pricing more reflective of higher energy value when operating reserves are scarce or constrained.

The PUCT directed the implementation of the ORDC in 2014 to act as the primary scarcity pricing mechanism, with subsequent amendments made in 2019, 2020 and 2021.

The majority of the retail load in the ERCOT market region is served by competitive retail suppliers, except certain areas that have not opted into competitive consumer choice and are served by municipal utilities and electric cooperatives.

While most of the states in the East region have introduced some level of retail consumer choice for electricity and/or natural gas, the incumbent utilities currently provide default service in most of the states and as a result typically serve the majority of residential customers.

NRG’s retail activities in the East are subject to standards and regulations adopted by the ISOs and state public utility commissions, including the requirement for retailers to be certified in each state in order to contract with end-users to sell electricity.

While most of the states in the East region of the U.S.

have introduced some level of retail consumer choice for electricity and/or natural gas, the incumbent utilities currently provide default service in most of the states and as a result typically serve the majority of residential customers.

NRG’s retail activities in the East are subject to standards and regulations adopted by the ISOs, state public utility commissions and legislators, including the requirement for retailers to be certified in each state in order to contract with end-users to sell electricity.

(a) The Cottonwood facility is located in Deweyville, Texas, but operates in the MISO market

NRG's power plants and demand response assets located in the East region of the U.S.

are within the control areas of ISO-NE, MISO, NYISO and PJM.

Power plants owned, operated and managed by NRG and NRG's demand response assets located in the East region of the U.S.

are within the control areas of PJM, NYISO and MISO.

Each of the market regions in the East region provides for robust competition in the day-ahead and real-time energy and ancillary services markets.

Additionally, the East region receives a significant portion of its revenues from capacity markets.

PJM and ISO-NE use a three-year forward capacity auction, while NYISO uses a month-ahead capacity auction.

MISO has an annual auction, known as the Planning Resource Auction.

Additionally, the assets in the East region receive a significant portion of their revenues from capacity markets.

PJM uses a forward capacity auction, while NYISO uses a month-ahead capacity auction.

MISO has an annual auction.

Capacity market prices are sensitive to design parameters, as well as additions of new capacity.

Both ISO-NE and PJM operate a pay-for-performance model where capacity payments are modified based on real-time generator performance.

In such markets, NRG’s actual capacity revenues will be the combination of cleared auction prices times the quantity of MWs cleared, plus the net of any over-performance "bonus payments" and any under-performance charges.

PJM operates a pay-for-performance model where capacity payments are modified based on real-time generator performance.

In such markets, NRG’s actual capacity revenues will be the combination of cleared auction prices times the quantity of MW cleared, plus the net of any over-performance "bonus payments" and any under-performance charges.

Additionally, bidding rules allow for the incorporation of a risk premium into generator bids.

In the West region of the U.S., NRG operates a fleet of natural gas-fired power plants located entirely within the CAISO footprint.

In the West region of the U.S., NRG owns equity interests in natural gas-fired power plants located entirely within the CAISO footprint.

The CAISO operates day-ahead and real-time locational markets for energy and ancillary services, while managing congestion primarily through nodal prices.

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Additionally, the CAISO has independent authority to contract with needed resources under certain circumstances, typically either when LSEs have failed to procure sufficient resources, or system conditions change unexpectedly.

In Canada, NRG sells to residential and commercial retail customers in Alberta under both regulated rates approved by the AUC as well as through competitive service with rates set by the market.

In Canada, NRG sells to residential and commercial retail customers in Alberta under both regulated rates approved by the AUC as well as through competitive service.

The Company's regulated rates are approved through periodic rate applications that establish rates for power and gas sales as well as for recovery of other costs associated with operating the regulated business.

In addition, the Company conducts retail sales of energy to commercial customers in other provinces.

All sales and operations are subject to applicable federal and provincial laws, regulations and licensing requirements.

In addition, the Company sells energy to commercial customers in other provinces.

All sales and operations are subject to applicable federal and provincial laws.

Regulatory Matters

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NRG must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where NRG operates.

Since entering office in January 2021, the President has signed a package of executive orders which, amongst other things, intends to boost the federal government's response to COVID-19, as well as elevate climate change across all levels and jurisdictions of the federal government.

The administration has requested all agencies delay submitting rules to the Federal Register or posting their effective date for 60 days if not already effective, until they can be reviewed by appointees of the current administration.

NRG is closely monitoring agency action as the orders will likely result in the promulgation of new regulations, where applicable.

NRG's operations within the ERCOT footprint are not subject to rate regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce.

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Federal Energy Regulation

Circuit Ruling on FERC's Use of Tolling Orders — On June 30, 2020, the U.S.

Court of Appeals for the D.C.

Circuit issued a decision stating that FERC's ability to "toll" actions on rehearing beyond the statutory 30-day period is unlawful.

On September 17, 2020, FERC staff explained that in Federal Power Act cases, it will no longer issue tolling orders but instead will issue either a Notice of Denial of Rehearing by Operation of Law or a Notice of Denial of Rehearing by Operation of Law and Providing for Further Consideration.

The first indicates that FERC would not intend to issue a merits order and the second indicates that FERC intends to issue further action.

This decision impacts an array of appeals related to the PJM MOPR order and will impact how rehearings are decided and appeals filed.

In March 2021, President Biden announced a framework for his "Build Back Better" initiative which includes policies to address climate change across the whole of the federal government through the tax code, an energy efficiency and clean energy incentives, research and development, among other areas of focus.

The "Build Back Better" initiative has taken the form of two separate bills in Congress.

The $1.2 trillion "core infrastructure" bill, which contains spending on new electric vehicle charging programs, among other things, was signed into law by President Biden on November 15, 2021.

The remaining priorities, commonly referred to as "Build Back Better," are being monitored by NRG as they progress through the legislative process.

State and Provincial Energy Regulation

State Proceedings Regarding States’ Participation in the Wholesale Market — Various states, including Connecticut, New Jersey, and New York as well as the District of Columbia have initiated proceedings to investigate resource adequacy alternatives and to consider its participation in the regional wholesale electricity market constructs, specifically withdrawal from the regional market or implementing a Fixed Resource Requirement Regime.

Any actions taken by the states could affect market design and market prices in the respective regional markets.

Illinois Legislation — Illinois enacted the Climate and Equitable Jobs Act ("CEJA") on September 15, 2021, which targets 100% clean energy by 2050.

CEJA focuses on (i) decarbonization, (ii) incentives to transition coal plants into clean energy facilities and (iii) nuclear subsidies.

CEJA requires non-publicly owned coal or oil electric generating units larger than 25 MWs to eliminate CO2e and copollutant emissions by January 1, 2030.

Non-publicly owned electric generating units that are gas-fired, including Joliet, must eliminate CO2e and copollutant emissions, including through unit retirement or the use of 100% green hydrogen, in a timeframe ranging from January 1, 2030 to January 1, 2045 depending on certain emission rates and proximity to environmental justice communities.

Furthermore, CEJA placed restrictions, with immediate effect, on gas-fired units that limits future emissions to their historic baselines.

These limits affect the total potential energy production by gas units in Illinois.

PJM, the PJM Independent Market Monitor and the Illinois Environmental Protection Agency have exchanged

correspondence to obtain clarification on the implications of these restrictions.

The new energy law also provides $174 million in incentives to develop solar and battery storage at coal generating sites that may be available to NRG.

Regional Regulatory Developments

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For further discussion on regulatory developments see Item 15 — Note 24, Regulatory Matters, to the Consolidated Financial Statements.

Capacity Market Reforms Filing — On December 19, 2019, FERC issued an order on the pending proposals to reform the PJM market to mitigate subsidized resources in the capacity market.

FERC directed PJM to apply the Minimum Offer Price Rule, or MOPR, to new and existing resources receiving state subsidies and subject them to default offer floor prices in their capacity bids.

The Order provided for various category specific exemptions to the MOPR, as well as a unit specific exemption, which permits any resource that can justify an offer lower than the default offer price floor to submit such capacity bids to PJM for review.

After subsequent filings and orders, on November 13, 2020, PJM submitted its third compliance filing, including a timeline to hold the next Base Residual Auction for Delivery Year 2022-2023 on May 19-25, 2021, which was accepted by FERC.

Multiple parties filed appeals in this matter, which have been consolidated at the Seventh Circuit Court of Appeals.

Subjecting subsidized resources to default offer floors in the capacity market should protect the market from further price suppression.

The impact of these changes on capacity market outcomes depends on, among other factors, bidding behavior, load forecast changes, new resource entry, and existing resource exit.

Indiana Municipal Power Agency and City of Lawrenceburg, Indiana Complaint on Station Power — On September 17, 2020, FERC issued an order in response to a complaint and request for declaratory judgement challenging the station power wholesale netting provisions in PJM's tariff.

FERC found that it does not have jurisdiction over the supply of station power and the provision of station power is a retail sale subject to state jurisdiction.

The order established a Section 206 proceeding and required PJM to submit a filing within 60 days to show why the station service netting provisions of its tariff are just and reasonable.

Lawrenceburg Power, LLC filed for rehearing, which was denied by operation of law on November 19, 2020 and they subsequently appealed to the United States Court of Appeals for the District of Columbia Circuit.

The matter is pending.

On November 23, 2020, PJM submitted its station power compliance filing to FERC.

Multiple parties filed comments and protests to PJM's compliance filing.

This decision could affect the rates that plants pay for station power.

PJM's ORDC Filing and Compliance Directives — On March 29, 2019, PJM proposed energy and reserve market reforms to enhance price formation in reserve markets, which includes modifying its ORDC and aligning market-based reserve product in Day-Ahead and Real-Time markets.

On May 21, 2020, FERC approved PJM's proposed energy and reserve market reforms.

FERC also directed PJM to implement a forward-looking Energy and Ancillary Services Offset to be used in PJM's capacity markets.

PJM submitted a compliance filing to revise its tariff on August 5, 2020.

On November 12, 2020, FERC approved two PJM compliance filings regarding PJM's reserve markets and the forward-looking Energy and Ancillary Services Offset and subsequently issued a timeline to hold the Base Residual Auction as noted above.

PJM will implement the forward-looking Energy and Ancillary Services Offset for the 2022/2023 Base Residual Auction.

ISO-NE Inventoried Energy Compensation Proposal — FERC approved ISO-NE's proposed interim measure to address near-term fuel security concerns by operation of law.

After an appeal to the Court of Appeals and a remand back to FERC, FERC issued an order accepting Inventoried Energy Compensation Proposal and by operation of law denied requests for rehearing on August 20, 2020.

Multiple parties filed amended petitions for review to include FERC's order on remand.

ISO-NE's proposal will affect future capacity market prices and the compensation that fuel secure units receive.

Mystic's Complaint on Transmission Reliability Review — On June 10, 2020, Constellation Mystic Power LLC filed a complaint at FERC against ISO-NE alleging that ISO-NE violated its Tariff in its addition of language to its planning procedure and in its conduct in carrying out a competitive transmission REP to address the retirements of Mystic Units 8 and 9.

On August 17, 2020, FERC issued an order denying the complaint.

After a rehearing that was denied by operation of law, on January 4, 2021, Constellation Mystic Power LLC filed an appeal to the D.C.

The outcome of this proceeding affects the retirement of the Mystic Units 8 and 9, thereby affecting capacity prices in ISO-NE.

Paper Hearing on ISO-NE's New Entrant Rule — On July 1, 2020, FERC issued an order establishing a Section 206 hearing initiated by FERC's preliminary finding that the "new entrant rules" may be unjust and unreasonable, specifically as it relates to the seven-year price-lock rule as a result of the D.C.

Circuit Court's remand on a FERC Order.

The price-lock mechanism permits qualified new resources that clear the auction to receive their first-year clearing price for seven years.

On December 1, 2020, FERC issued an order eliminating the seven-year price lock rule beginning in Forward Capacity Auction 16.

The elimination of the seven-year price lock rule could affect future capacity prices in ISO-NE.

Competitive Auctions with Sponsored Resources Proposal (CASPR) — On January 8, 2018, ISO-NE filed the CASPR proposal which attempts to accommodate state sponsored resources while maintaining competitive market pricing.

On November 19, 2020, FERC upheld the order approving CASPR.

Multiple parties filed an appeal to the D.C.

The outcome of this proceeding will potentially affect future capacity market prices.

New York State Public Service Commission Retail Energy Market Proceedings — On February 23, 2016, the NYSPSC issued an order referred to as the Retail Reset Order.

Among other things, the Retail Reset Order placed a price cap on energy supply offers and imposed burdensome new regulations on ESCO's.

Various parties have challenged the NYSPSC's authority to regulate prices charged by competitive suppliers.

On May 9, 2019 the New York Court of Appeals, the state’s highest tribunal, issued a decision affirming the NYSPSC’s authority to regulate ESCO’s prices as a condition of access to the utilities’ infrastructure.

On December 12, 2019, the NYSPSC issued an order limiting ESCO's offers for electric and natural gas to three compliant products:

guaranteed savings from the utility default rate, a fixed term capped at 5% of the rolling 12-month average utility default rate, or NY-sourced renewable energy that is at least 50% greater than the prevailing NY Renewable Energy Standard for load serving entities.

The Order effectively limited ESCO offers to natural gas customers to only the guaranteed savings and capped fixed term compliant products because no equivalent renewable energy product exists for natural gas.

The Order also establishes new ESCO eligibility criteria and certification process, as well as re-certification of current ESCOs.

Multiple parties filed for rehearing, which were denied.

After extension requests, the NYSPSC ordered compliance effective April 16, 2021.

On January 21, 2021, the NYSPSC issued an Order setting a timeline to evaluate additional compliant energy-related value-added products and also provided for a limited one-year waiver whereby ESCOs, including NRG's Green Mountain Energy and XOOM Energy, which currently offer green gas products, could continue to serve existing customers.

The limited offerings imposed by the Order, as issued, may impact the Company's retail sales to Mass Market customers in New York, although the Company is currently in the process of moving existing customers to compliant products.

New York Buyer Side Mitigation Proceedings — On February 20, 2020, FERC issued multiple orders pertaining to the NYISO capacity market.

The orders narrowed certain exemptions to buyer side mitigation measures.

Specifically, FERC stated that certain renewable and self-supply resources would be exempt from offer floor mitigation but rejected NYISO’s proposal of a 1,000 MW cap on renewable resources that could qualify for the exemption.

FERC ordered NYISO to make a compliance filing narrowly tailoring its cap.

The NYISO submitted its compliance filing, which FERC largely accepted.

FERC rejected a complaint to exempt new electric storage resources and also rejected a blanket exemption to demand response providers currently subject to mitigation but granted a request for new demand response to receive a blanket exemption from the buyer side mitigation measures.

On June 18, 2020, the NYSPSC filed petitions for review with the D.C.

Circuit regarding these buyer side mitigation orders, but the appeals were held in abeyance pending FERC's consideration of rehearing requests.

On December 7, 2020, FERC denied rehearings by operation of law regarding the exemption to demand response providers.

FERC sustained its position in an October 15, 2020 order regarding the rehearing on electric storage resources.

Parties have re-appealed the order regarding electric storage resources.

Implementation of buyer side mitigation measures to address price suppression provides more accurate capacity price signals in the competitive market.

New York Generators' Complaint on Buyer Side Mitigation Rules — On October 14, 2020, two New York generators, Cricket Valley and Empire Generating, filed a complaint at FERC against the NYISO arguing that the NYISO's offer floor rules are unjust and unreasonable because they do not address price suppression in the market.

The complaint requests that FERC order the NYISO to implement a MOPR that covers out-of-market support to new and existing resources, similar to that in PJM.

The outcome of this proceeding could affect capacity market prices in New York.

The complaint remains pending at FERC.

Public Utility Commission of Texas’ Actions Related to COVID-19 — On March 26, 2020, the PUCT adopted the COVID-19 Electricity Relief Program ("ERP") aimed to mitigate the impact of COVID-19 on residential customers in the competitive retail electric market who are experiencing economic hardship as a result of the pandemic.

The COVID-19 ERP protected residential customers deemed eligible by the PUCT’s third party administrator from disconnection for nonpayment until September 30, 2020 and established an emergency fund to allow Retail Electric Providers ("REPs") to recover a certain amount of credit losses incurred while continuing to serve these customers.

Final reimbursement requests by REPs were due by November 30, 2020.

California Resource Adequacy Proceedings — Since a summer 2020 heat storm that resulted in emergency load curtailments, the State of California and CAISO have embarked on numerous new regulatory activities while redirecting existing proceedings related to the topic of resource adequacy.

In a rulemaking docket, on December 28, 2020, the CPUC directed the state's major investor-owned utilities to engage in emergency procurement for 2021 and 2022.

In the same docket, the CPUC is considering ways to increase the volume of demand response available to the state during emergency conditions.

The CPUC is also considering longer term structural reforms of the resource adequacy policy in California.

Additionally, the CAISO has indicated it will procure resources to a higher reserve margin in 2021 than it employed in 2020, while evaluating the conditions likely to exist at early-evening hours when peak load, net of solar resources, is highest.

Midway-Sunset RMR Proceeding — San Joaquin Energy, LLC, a subsidiary of NRG, owns a 50%, non-controlling interest in the Midway-Sunset Cogeneration Company ("MSCC").

MSCC owns a cogeneration facility near Fellows, CA and submitted mothball notices for the cogeneration facility to the CAISO in the latter half of 2020.

On December 17, 2020, the CAISO Board effectively rejected the mothball notices by authorizing its staff to designate the MSCC facility as a reliability must-run resource conditioned on execution of a RMR contract.

In a letter dated December 16, 2020 sent to the CAISO Board, MSCC indicated that it did not object to the RMR designation but noted certain permitting and maintenance requirements for RMR operation.

Public Utility Commission of Texas’ Actions with Respect to Wholesale Pricing and Market Design — In September 2021, the PUCT opened a rulemaking project to evaluate whether it should amend its rules to modify the High System Wide Offer cap ("HCAP") and the ORDC, which is intended to ensure prices in the competitive market appropriately reflect the value of operating reserves as the system approaches scarcity conditions.

This rulemaking project concluded in December 2021, resulting in a rule amendment that lowered the HCAP to $5,000 per MWh and which expands the minimum contingency level to 3,000 MW.

These two changes are broadly offsetting in their effect on overall average energy prices.

Activity on Securitization and ERCOT Pricing during Winter Storm Uri — The Texas Legislature acted to pass a variety of securitization vehicles to finance exceptionally high power and gas costs from Winter Storm Uri, including HB 4492.

ERCOT subsequently filed two applications requesting the PUCT to issue Debt Obligation Orders ("DOOs") based on the legislation.

On October 13, 2021, the PUCT issued DOOs authorizing ERCOT's securitization of $800 million to cover short payments and reimburse congestion revenue right account holders for amounts related to the default of market participants other than electric cooperatives Brazos and Rayburn, which are discussed below (the "Default Securitization") and $2.1 billion related to highly priced ancillary service and ORPDA during Winter Storm Uri (the "Uplift Securitization").

The DOOs require ERCOT to issue loans or securitized bonds through a bankruptcy remote special purpose entity as the borrower and distribute the proceeds to affected market participants for default-related short payments and to LSEs for certain ancillary-service and ORDPA costs using an allocation of proceeds based on an LSE's exposure to relevant costs as calculated by the LSE's prevailing load-ratio share during the period of Winter Storm Uri, and a further redistribution of proceeds initially allocated to other LSEs and customers who opt-out of securitization.

In turn, ERCOT will charge non-bypassable fees related to the Default Securitization and Uplift Securitization to all qualified scheduling entities and to all LSEs (other than those that have opted-out), respectively.

The Uplift Securitization provided for a one-time opt-out for certain LSEs or individual transmission-level customers who in exchange for foregoing any securitization-related proceeds likewise avoid future fees assessed by ERCOT for the use of repaying ERCOT's debt obligations.

However, nearly all competitive REPs were required by the law to participate, ensuring the charge established by the law is competitively neutral.

These opt-outs and calculations of the allocation of proceeds have been finalized.

Based on LSE-level detail published by the PUCT on December 7, 2021, NRG will receive $689 million of Uplift Securitization proceeds, with receipt expected to occur during the second quarter of 2022.

The $800 million Default Securitization was disbursed by ERCOT in November 2021, with NRG receiving $12 million.

Electric Cooperative Bankruptcy and Securitization — Of the defaults in the ERCOT market, two electric cooperatives, Brazos and Rayburn, constitute the vast majority.

Brazos currently is in bankruptcy.

NRG and ERCOT have both filed a proof of claim in the bankruptcy proceeding of Brazos, and Brazos has challenged ERCOT's claims in a manner that may prejudice NRG's claims against Brazos.

During the fourth quarter of 2021, ERCOT filed a motion to dismiss Brazos' complaint relating to ERCOT's proof of claim, which NRG joined in support, but this motion was denied by the Bankruptcy Court, and ERCOT, NRG and certain other parties appealed.

On January 11, 2022, the United States District Court for the Southern District of Texas entered an order allowing the appellants to seek direct review from the Fifth Circuit Court of Appeals of the Bankruptcy Court's decision on the motion to dismiss.

On January 18, 2022, ERCOT, NRG and certain other parties filed a petition for direct review by the United States Court of Appeals for the Fifth Circuit.

The Court of Appeals granted the petition on February 4, 2022.

On February 7, 2022, the Bankruptcy Court entered an order granting summary judgement in favor of Brazos on whether ERCOT's sales to Brazos were in the ordinary course of Brazos' business.

The Bankruptcy Court ruled that the portion of ERCOT's claims for charges incurred by Brazos after the intervention of the PUCT and ERCOT were not in the ordinary course and thus are not entitled to administrative expense status under the Bankruptcy Code.

The amount and priority of ERCOT's claim for amounts incurred prior to such intervention or after such intervention ceased are issues to be determined at trial.

The Bankruptcy Court's summary judgement ruling may also apply to NRG's claims again Brazos.

Trial on the merits of the ERCOT proof of claim and Brazos' complaint is set to commence before the Bankruptcy Court on February 22, 2022.

To the extent the Bankruptcy Court reduces or disallows claims against Brazos, this presents risk for NRG.

ERCOT's market protocols provide for short payments to be extinguished through a process of uplift, whereby the cost of defaults is allocated to all market participants, including retailers, generators, municipal and cooperative utilities, and financial traders.

However, the total amount of this uplift is limited by ERCOT's current protocols of $2.5 million per month.

Consequently, it would take approximately 63 years for the net short-pay balance of $1.887 billion related to Brazos to be uplifted to the market under the current market rules.

NRG's undiscounted share of the uplift based on its current market share

is estimated to be approximately $121 million and has been short-paid $68 million.

The remaining $53 million has been discounted based on the 63 year repayment term and present value of $9 million was recorded as an additional liability.

Rayburn announced that it intended to securitize the amounts owed to ERCOT and payment from such securitization is expected in the first quarter of 2022.

Reliability and Plant Operations Standards — The PUCT established a rulemaking to establish weatherization standards, and issued a notice for comments in response to provisions of Texas Senate Bill 3 ("SB3") that require mandatory standards for power generators and others within the electric-power sector.

SB3 provides that the standards adopted by the PUCT be implemented by generation owners, be subject to ERCOT inspections, and that ERCOT provide asset owners with a reasonable period of time to remedy any violation.

Continuing violations would be subject to an administrative penalty and a requirement that a third-party contractor assess the asset owner's weatherization plans.

On August 24, 2021, Commission Staff issued a proposal of weatherization standards for publication.

NRG, through its trade association, filed comments.

On October 21, 2021, Commissioners of the PUCT voted to adopt the rule without substantial modifications from the proposal.

PJM’s Variable Resource Requirement Curve — On July 9, 2021, the Court of Appeals for the D.C.

Circuit issued a decision denying in part and granting in part an appeal by several PJM state consumer advocates regarding FERC’s order approving revisions to PJM’s Variable Resource Requirement Curve (“VRR”).

The court upheld PJM's use of a greenfield gas-fired combustion turbine as the reference unit to establish Net Cost of New Entry ("Net CONE").

However, the court remanded back to FERC the issue of allowing generators to have a 10% adder to their offer to supply capacity in the PJM market, and on January 20, 2022, FERC issued an order removing the 10% adder.

The VRR is the demand curve that represents the slope of bids in the auction that ultimately results in the price and quantity of capacity allocated to load-serving entities, including NRG.

The VRR curve is based on several inputs, including the Net CONE.

The outcome could affect PJM’s capacity market prices.

PJM Revisions to Minimum Offer Price Rule — On July 30, 2021, PJM filed proposed tariff changes at FERC to largely eliminate the current minimum offer price rules ("MOPR") except in very narrow cases.

The proposal would eliminate:

(i) the current MOPR for new entrant natural gas resources effective with the 2023/2024 delivery year and (ii) the expanded MOPR established in FERC's December 2019 Order to address out-of-market subsidies.

On September 30, 2021, PJM's proposal went into effect by operation of law because the FERC Commissioners were split 2-2 as to the lawfulness of the change.

Multiple parties filed motions for rehearing and ultimately appealed to the federal court of appeals.

On December 21, 2021 and December 30, 2021, respectively, the Third Circuit Court of Appeals and the Seventh Circuit Court of Appeals issued an order holding the appeals in abeyance.

The proposed revisions would allow PJM to address specific and narrow instances of buyer-side market power through subsequent filings at FERC.

Any changes to the PJM capacity market construct may impact the outcome of future Base Residual Auctions.

PJM's ORDC Filing and Compliance Directives — On May 21, 2020, PJM proposed energy and reserve market reforms to enhance price formation in reserve markets, which included modifying ORDC and aligning market-based reserve products in Day-Ahead and Real-Time markets.

In addition to approving PJM's proposal, FERC also directed PJM to implement a forward-looking Energy and Ancillary Services Offset to be used in PJM's capacity markets.

After multiple compliance filings, parties filed appeals at the Court of Appeals for the D.C.

Circuit of FERC’s orders, and on August 13, 2021, FERC filed a motion and was granted a voluntary remand the case back to the agency.

On December 22, 2021, FERC issued its order on voluntary remand affirming in part and reversing in part FERC's determination.

Specifically, FERC reversed itself and ordered PJM to:

(i) eliminate the more robust ORDC curves and reserve penalty adders and maintain the existing (lower) curves and (lower) penalty adders and (ii) restore its tariff provisions related to its prior backward-looking Energy and Ancillary Services Offset.

At the direction of FERC, on January 21, 2022, PJM filed a compliance fling proposing a new schedule for the Base Residual Auctions.

Independent Market Monitor Market Seller Offer Cap Complaint — On March 18, 2021, finding that the calculation of the default Market Seller Offer Cap was unjust and unreasonable, the Order permitted the current PJM May 2021 capacity auction for the 2022/2023 delivery rule to continue under the existing rules and set a procedural schedule for parties to file briefs with possible solutions.

On September 2, 2021, FERC issued an order in response to a complaint filed by the PJM Independent Market Monitor's proposal, which eliminates the Cost of New Entry-based Market Seller Offer Cap and implements a limited default cap for certain asset classes based on going-forward costs and provides for unit specific cost review by the Independent Market Monitor for all other non-zero offers into the auctions.

As required by the Order, PJM submitted its compliance tariff on October 4, 2021.

On October 4, certain parties filed a motion for rehearing.

which was denied.

Multiple parties filed appeals at the Court of Appeals for the D.C.

The appeals are currently being held in abeyance.

The removal of the Offer Caps may impact the outcome of future Base Residual Auctions.

NYISO's Revisions to the Buyer Side Mitigation Rules — On January 5, 2022, the NYISO filed its Comprehensive Mitigation Review proposing changes to the buyer-side mitigation rules.

The proposal would remove certain facilities to be reviewed under the buyer-side mitigation rules to serve the goals of New York's Climate Leadership and Community Protection Act, adopt a marginal capacity accreditation market design and adjust the rules surrounding installed and unforced capacity.

Changes to NYISO's Buyer Side Mitigation rules may impact the outcome of future capacity auctions.

California Resource Adequacy Proceedings — On March 25, 2021, the CPUC directed the state's major investor-owned utilities to engage in up to 1.5 GW of emergency procurement for 2021 and 2022 and is currently evaluating further procurement directives through 2023.

In the same docket, the CPUC approved a new demand response program for use during emergency conditions.

As part of the Integrated Resource Procurement docket, the CPUC approved a decision on June 24, 2021 that will require all Load Serving Entities to procure a pro rata share of 11.5 GW of new non-fossil resource adequacy from 2023 to 2026.

To replace the retiring Diablo Canyon nuclear plant, this will consist largely of GHG-free energy, long-duration storage, baseload renewables and energy storage.

A new resource adequacy docket opened in October 2021 will consider changes to the reserve margin and qualifying capacity of different resource types, and the CPUC and CAISO will continue to evaluate major structural reforms to the resource adequacy program in California that would begin in 2024.

Midway-Sunset Reliability Must Run Proceeding — San Joaquin Energy, LLC, a subsidiary of NRG, owns a 50%, non-controlling interest in the Midway-Sunset Cogeneration Company ("MSCC").

MSCC owns a cogeneration facility near Fellows, California and submitted mothball notices for the cogeneration facility to the CAISO in the latter half of 2020.

On December 17, 2020, the CAISO Board effectively rejected the mothball notices by authorizing its staff to designate the MSCC facility as a reliability must-run ("RMR") resource conditioned on execution of a RMR contract.

On January 29, 2021, MSCC made its RMR filing at FERC.

Multiple parties filed protests and on March 16, 2021, MSCC filed a response to those protests.

On April 2, 2021, FERC accepted the RMR filing, suspended it to become effective February 1, 2021 subject to refund and established hearing and settlement judge proceedings.

The parties are engaging in settlement proceedings.

On September 27, 2021, the CAISO gave notice to MSCC extending the term of the reliability designation through December 31, 2022.

Alberta Energy Market — In December 2020, prior to its acquisition by NRG, Direct Energy filed a Non-Energy Rate Application with the AUC to approve cost recovery for the 2020-2022 period.

Major cost elements of this application relate to bad debt, corporate costs, and customer care and billing contracts.

The Company is engaged in a mediation and settlement process.

Typically, AUC proceeding take 12-18 months to reach resolution, if settlement procedures do not result in the resolution of contested issues more quickly.

The AUC's decision ultimately will result in a surcharge or rebate to adjust collected revenues to AUC-approved costs for the 2020-2022 period.

The Company also is waiting on a final review and approval from the AUC of a negotiated rate settlement for its electricity focused 2020-2022 Energy Price Setting Plan, of which a decision is expected during the first quarter of 2021.

The Company is also in the process of repaying the remainder of amounts advanced to it from the Balance Pool and the Alberta government as part of its 90 day utility bill deferral program.

The Company engaged in a mediation and settlement process, and on April 20, 2021 an all-party settlement was executed, and was filed with the AUC on April 23, 2021.

The AUC approved the settlement agreement on June 4, 2021.

Separately, the Company received approval from the AUC of a negotiated rate settlement for its electricity focused 2020-2022 Energy Price Setting Plan which went into effect on July 1, 2021.

The Company has completed the last repayment to the Balancing Pool and the Alberta government as part of its 90-day utility bill deferral program.

This program, effective March 18, 2020, was designed to assist residential, farms, and small business customers who were negatively affected by COVID-19 related economic circumstances by temporarily deferring their utility bill payments.

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Complying with environmental laws often involves specialized human resources and significant capital and operating expenses, as well as occasionally curtailing operations.

The COVID-19 pandemic may prevent the Company from complying with certain of its environmental requirements, which federal and state regulators have recognized.

NRG decides to invest capital for environmental controls based on the relative certainty of the requirements, an evaluation of compliance options, and the expected economic returns on capital.

A number of regulations that affect the Company have been revised recently by the EPA, including ash storage and disposal requirements, NAAQS revisions and implementation and effluent limitation guidelines.

Some of these recent revisions may, in turn, be revised by the new U.S.

Some of these recent revisions may, in turn, be revised by the current U.S.

presidential administration.

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Under the CAA, the EPA sets NAAQS for certain pollutants including SO 2 , ozone, and PM2.5.

Many of the Company's facilities are located in or near areas that are classified by the EPA as not achieving certain NAAQS (non-attainment areas).

Many of the Company's facilities are located in or near areas that are

classified by the EPA as not achieving certain NAAQS (non-attainment areas).

The relevant NAAQS may become more stringent.

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Circuit vacated the ACE rule (but on February 22, 2021, at the EPA's request, stayed the issuance of the portion of the mandate that would vacate the repeal of the CPP).

Accordingly, we expect the EPA to promulgate a new rule to regulate GHG emissions from power plants.

On October 29, 2021, the U.S.

Supreme Court agreed to review the D.C.

Circuit's decision, which should provide some clarity regarding the scope of the EPA's authority to regulate CO 2 under the Clean Air Act.

The Company expects the EPA to promulgate a new rule to regulate GHG emissions from power plants after a decision from the U.S.

Supreme Court.

Greenhouse Gas Emissions — NRG emits CO 2 (and small quantities of other GHGs) when generating electricity at a majority of its facilities.

The graphs presented below illustrate NRG's domestic emissions of CO 2 e for the 2014, and the 2018 through 2020 period.

Nearly all (>99%) of NRG's GHG emissions are subject to federal (U.S.

Nearly all (>99%) of NRG's domestic GHG emissions are subject to federal (U.S.

EPA) GHG reporting requirements.

In 2019, NRG announced the acceleration of its science-based GHG emissions reduction goals to align with prevailing climate science, which seeks to limit global warming in the post-industrial era to 1.5 degrees Celsius.

NRG is targeting a 50% reduction by 2025, from its current 2014 baseline, and net-zero emissions by 2050.

From 2014 to 2020, the Company's CO 2 e emissions decreased from 63 million metric tons to 28 million metric tons, representing a cumulative 55% reduction.

The decrease is attributed to reductions in fleet-wide annual net generation, a market-driven shift away from coal as a primary fuel to natural gas, and in 2020 reduced load as a result of the COVID-19 pandemic.

The Company believes the 2020 emissions level may change as load recovers from the impact of COVID-19.

NRG's climate goals are to reduce greenhouse gas emissions by 50% by 2025, from its current 2014 baseline, and to achieve net-zero emissions by 2050.

Greenhouse gas emissions include directly controlled emissions, emissions from NRG's purchased energy, and emissions from employee business travel.

In 2021, NRG's climate goals were certified by the Science Based Targets initiative as aligned with a 1.5 degree Celsius trajectory.

From the current 2014 baseline to 2021, the Company's CO 2 e emissions decreased from 61 million metric tons to 34 million metric tons, representing a cumulative 44% reduction.

The decrease is attributed to reductions in fleet-wide annual net generation and a market-driven shift away from coal as a primary fuel to natural gas.

The increase in emissions in 2021, as compared to 2020, was primarily due to higher power demand which was a result of the easing of COVID-19 pandemic lockdowns and the associated economic recovery.

The Company is continuing to target a 50% reduction by 2025 and is on track to meet that goal.

As of December 31, 2021, less than 5% of the Company's consolidated operating revenues were derived from coal-fired operating assets.

The following tables reflect the Company’s generation portfolio, including leased facilities and those accounted for through equity method investments.

The following charts reflect the Company’s domestic generation portfolio, including leased facilities and those accounted for through equity method investments.

Prior year information was adjusted to remove divested assets.

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Alternative Demonstration for Unlined Surface Impoundments," which further amended the April 2015 Rule to, among other things, provide procedures for requesting approval to operate existing ash impoundments with an alternate liner.

The Company has updated its estimates of required environmental capital expenditures to address this revised rule.

Domestic Site Remediation Matters

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As with air quality regulations, federal and state water regulations have become more stringent and imposed new requirements.

Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which imposed more stringent requirements (as individual permits were renewed) for wastewater streams from FGD, fly ash, bottom ash, and flue gas mercury control.

Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines ("ELG") for Steam Electric Generating Facilities, which imposed more stringent requirements (as individual permits were renewed) for wastewater streams from FGD, fly ash, bottom ash, and flue gas mercury control.

On September 18, 2017, the EPA promulgated a final rule that, among other things, postponed the compliance dates to preserve the status quo for FGD wastewater and bottom ash transport water by two years to November 2020 until the EPA amended the rule.

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and (iii) changing several deadlines.

The Company is in the process of estimating the environmental capital expenditures that will be required to comply.

The capital expenditures required to comply will depend on elections regarding future operations of each coal-fired unit.

NRG expects to make these elections for each unit in Q4 2021 at which time the EPA will be notified as required.

Accordingly, we do not expect to provide estimates of ELG compliance costs until early 2022.

On July 26, 2021, the EPA announced that it is initiating a new rulemaking to evaluate revising the ELG rule.

While the EPA is developing the new rule, the existing rule (as amended in 2020) will stay in place, and the EPA expects permitting authorities to continue to implement the current regulation.

The EPA anticipates releasing a proposed rule in fall 2022.

In October 2021, NRG informed its regulators that the Company intends to comply with the ELG by ceasing combustion of coal by the end of 2028 at its domestic coal units outside of Texas, and installing appropriate controls by the end of 2025 at its two plants in Texas.

Regional Environmental Developments

NY NOx — On December 31, 2019, the New York State Department of Environmental Conservation finalized a more stringent NOx regulation that will result in the retirement of the Company's combustion turbines in Astoria, New York in 2023.

Ash Regulation in Illinois — On July 30, 2019, Illinois enacted legislation that requires the state to promulgate regulations regarding coal ash at surface impoundments.

On March 30, 2020, the state released its proposed implementing regulations.

The Company expects the state to promulgate the final implementing regulations in March 2021, at which time regulated entities will then prepare and submit permit applications.

On April 15, 2021, the state promulgated the implementing regulation, which became effective on April 21, 2021.

The new regulation requires NRG to apply for initial operating permits for its coal ash surface impoundments by October 31, 2021 and construction permits (for closure) starting in 2022.

NRG sells to a wide variety of customers, primarily end-use customers in the residential, commercial and industrial sectors.

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NRG believes its employees are vital to its success and is committed to offering employees a rewarding career that provides opportunities for growth and the ability to make valuable contributions toward the achievement of the Company’s business objectives.

NRG focuses on safety, health and wellness, diversity and inclusion, talent development and total rewards for its employees.

NRG focuses on safety, health and wellness, diversity, equity and inclusion, talent development and total rewards for its employees.

Safety is embedded in the culture at NRG.

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NRG has achieved its targeted top decile safety record of Occupational Safety and Health Administration recordable injury rates in each of the 5 previous years.

Health and Wellnes s

Health and Wellness

For several years, NRG has invested in the well-being of its employees and their families.

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In response to COVID-19, NRG implemented additional programs to provide services to support the needs of employees, including those working from home, such as programs that provided back-up childcare, expanded access to telemedicine (for both physical and mental health), and supported mental and emotional well-being through programs such as mindfulness.

For a further discussion on the Company’s overall response to COVID-19, please see above in this Item 1 — Business under the caption COVID-19.

Diversity and Inclusion

NRG is committed to diversity and inclusion as an integral part of the Company.

During 2021, the Company continued its support of employees by partnering with the National Council for Behavioral Health to roll out their Mental Health First Aid program.

This program safely, respectfully and effectively opens the conversation about mental illness and addiction, encourages employees to recognize and take responsibility for their mental health, teaches managers to recognize and speak to an employee with a mental health concern before it creates performance problems, complements and supports existing benefit and wellness programs and company’s policies and procedures.

Diversity, Equity and Inclusion

NRG is committed to diversity, equity and inclusion ("DE&I") as an integral part of the Company.

In 2020, NRG completed a gender and race pay equity study to ensure that the Company's pay decisions were not influenced by gender, race, or other similar factors.

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NRG also conducted company-wide unconscious bias training to help all employees recognize, understand, and reduce implicit bias and offers various other related guides and tools to its employees and management.

In 2021, the Company focused on embedding DE&I in the Company’s operations, culture and communications, by working with diverse suppliers, finding diverse talent, facilitating engagement and awareness of DE&I by employees, and committing to be accountable for our DE&I progress.

Talent Development

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The Board of Directors also has a structured program that allows directors to interact directly with individuals deeper within the organization whom management, through a robust talent assessment program, as well as mentoring relationships, has identified as high potential future leaders.

In 2021, the Company launched an Executive Leadership Program to strengthen the identified pipeline of future leaders and create a cohort of high potential candidates for the program.

The Company has a performance management tool that emphasizes a continuous feedback loop and a robust online training curriculum with topics including leadership, communication and productivity.

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Every two years, the Company engages an independent third party to benchmark its compensation and benefits programs against its peers and report the results to the Compensation Committee of the Board of Directors.

For additional information and recent available data regarding the Company’s efforts and programs please see the Company’s 2020 Proxy Statement and 2019 Sustainability Report, which are available on the Company’s website at:

For further discussion and recent available data regarding the Company’s efforts and programs please see the Company’s 2021 Proxy Statement and 2020 Sustainability Report, which are available on the Company’s website at:

www.nrg.com .

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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 1. Business