NRG Energy, Inc.
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PART I
Item 1 — Business
General
NRG Energy, Inc., or NRG or the Company, serves electricity, natural gas, and smart-home technology solutions to approximately 8 million residential customers (comprised of 6 million retail energy and 2 million smart home), in addition to large commercial and industrial, data center, and wholesale customers. Across North America, NRG is redefining customers’ experience with energy under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy, and Vivint. As of December 31, 2025, the Company’s core power and natural gas business consists of approximately 12 GW of competitive power generation, primarily in Texas, and a natural gas portfolio that serves approximately 1,900 MMDth annually.
NRG sold 154 TWhs of electricity and 1,857 MMDth of natural gas in 2025, making it one of the largest competitive energy retailers in the U.S. As of the end of 2025, NRG had recurring electricity and/or natural gas sales in 25 U.S. states, the District of Columbia, and 8 provinces in Canada, and Vivint Smart Home served customers in all 50 U.S. states and the District of Columbia. NRG's retail brands, collectively, have the largest share of competitively served residential electric customers in Texas and is a leading business-to-business provider of power and natural gas in North America.
On January 30, 2026, NRG completed the acquisition of the LSP Portfolio, pursuant to the Purchase and Sale Agreement (the “Purchase Agreement”) dated as of May 12, 2025. The LSP Portfolio includes 18 natural gas-fired and dual fuel facilities totaling approximately 13 GW of capacity, located across nine states, as well as CPower, a leading demand response platform.
Strategy
NRG's strategy is to maximize shareholder value by delivering integrated energy and smart home solutions, supported by an owned generation fleet and a diversified supply strategy. The Company generates power and sells electricity and natural gas to residential, commercial, industrial, and wholesale customers in the markets it serves. The Company also provides smart home security and automation services that deepen customer relationships and support long-term engagement. NRG operates a customer-first platform that promotes reliability and affordability amid rapid transformation in the energy sector. The Company is advancing opportunities to meet growing demand, including from data centers, other large load customers, and electrification. This includes (i) demand response and virtual power plants (“VPP”), which help manage costs and improve affordability for customers, (ii) completing the Texas Development Projects, (iii) long-term, contract-backed generation and related infrastructure, supported by strategic partnerships with equipment manufacturers and engineering, procurement, and construction companies, and (iv) increasing capacity at existing facilities. The Company’s differentiated model is built to meet North America’s evolving needs while delivering affordable, reliable solutions for customers and long-term growth for shareholders. This strategy is intended to generate recurring cash flow, strengthen earnings and cost competitiveness, and reduce risk and volatility.
To effectuate the Company’s strategy, NRG is focused on: (i) serving the energy needs of residential, commercial and industrial, and wholesale counterparties in competitive markets and optimizing on additional revenue opportunities through its multiple brands and channels; (ii) offering a variety of energy products and smart home products and services that are differentiated by innovative, value-additive features, premium service, integrated platforms, sustainability, loyalty/affinity programs, and affordability; (iii) excellence in operating performance of its assets; (iv) achieving the optimal mix of supply to serve its customer load requirements through a diversified supply strategy, including expanding its operational capacity to meet growing retail power supply needs; and (v) engaging in disciplined and transparent capital allocation.
Business Overview
The Company’s core businesses are the sale of electricity and natural gas to residential, commercial and industrial and wholesale customers, supported by the Company's wholesale electric generation, as well as the sale of smart home products and services. NRG manages its electricity and natural gas operations based on the combined results of the retail, wholesale and generation businesses with a geographical focus. Vivint Smart Home operations are reported within the Vivint Smart Home segment.
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 all activity related to customer, plant and market operations in the East;
•West/Other, which primarily includes the following assets and activities: (i) all activity related to customer, plant and market operations in the West and Canada, and (ii) other investments;
•Vivint Smart Home; and
•Corporate activities.
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In Texas, the Company’s generation supply is fully integrated with its retail load. This integrated model provides the advantage of being able to supply a 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 more 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.
The integrated model consists of three core functions in each geographic segment above: Customer Operations, Market Operations and Plant Operations.
Customer Operations
Customer Operations is responsible for growing and retaining the customer base and delivering an outstanding customer experience. This includes acquisition and retention of all of NRG’s residential, small commercial, commercial and industrial, data centers and government customers. NRG employs a multi-brand strategy that leverages a wide array of sales and partnership channels, direct face-to-face sales channels, call centers, websites, and brokers. Go-to-market activities include market strategy planning and development, product innovation, offer design, campaign execution, marketing and creative services, and selling. Customer portfolio maintenance and retention activities include fulfillment, billing, payment processing, collections, customer service, issue resolution, and contract renewals. 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 customers typically contract for terms ranging from one year to five years in length and extended contractual terms are available. 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 market. Customer Operations primarily comprises two end-use customer facing teams: NRG Home, which serves residential customers, and NRG Business, which serves business customers.
Product Offerings
NRG sells a variety of products and services to residential and small commercial customers, in a wide variety of sales channels, including retail electricity, energy management, demand response and/or virtual power plant programs, natural gas, and carbon offsets. Home 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 seeks to attract, retain, and increase the value of its customer relationships by enhancing affordability. NRG's brands are recognized for exemplary customer service, innovative smart energy and environmentally-friendly solutions.
The Company provides power and natural gas, as well as retail services, to large business and commercial and industrial customers in North America. These solutions include system power, natural gas, demand response, distributed and backup generation, energy storage, energy management, renewable and low-carbon products and carbon management, energy efficiency, and bring your own power (“BYOP”) arrangements for large loads.
Market Operations
Market Operations has two primary objectives: to supply energy to customers in the most cost-efficient manner and to maximize the value of the Company's assets in satisfying its customer load requirements. These objectives are intended to reduce supply costs and maximize earnings with predictable cash flows.
Power and natural gas are the two main commercial groups within Market Operations.
Power
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 hedging agreements via a wide range of products and contracts, including (i) physical and financial commodity instruments, (ii) fuel supply and transportation contracts, and (iii) capacity and other contracted revenue or supply 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 commodity price risk.
Physical and Financial Commodity Instruments
NRG trades power, natural gas, environmental, weather and other physical and financial commodity related 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 and regulations.
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Fuel Supply and Transportation Contracts
NRG's fuel requirements consist of various forms of fossil fuel. The prices of fossil fuels can be volatile. The Company obtains its fossil fuels from multiple suppliers and through multiple transporters. Although availability is generally not an issue, localized shortages, transportation availability, delays arising from extreme weather conditions and supplier financial stability issues can and do occur. The preceding factors related to the sources and availability of raw materials are fairly uniform across the Company's business and fuel products used. NRG's primary fuel requirements consist of the following:
Natural Gas — NRG operates a fleet of mid-merit and peaking natural gas plants. Fuel needs are managed by the natural gas commercial group, generally on a spot basis, 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. Natural gas storage and transportation contracts are utilized to reduce daily volatility.
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 2026. As of December 31, 2025, NRG had purchased forward contracts to provide fuel for the Company's expected requirements for 2026. For the domestic fleet, NRG purchased approximately 15 million tons of coal in 2025, 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, which will provide for the Company's transportation requirements of Powder River Basin coal for the next four years.
Capacity and Other Contracted Revenue or Supply Sources
NRG's revenues and/or cash flows, primarily in the East and West, benefit from capacity/demand payments and other contracted revenue sources, originating from market clearing capacity prices, tolling arrangements and other long-term contractual arrangements.
Natural Gas
The natural gas commercial group is responsible for costing, logistics and supply for all of NRG's residential, commercial and industrial, and wholesale customers. NRG has contractual rights to natural gas transportation and storage assets across its footprint that allow for optimal supply economics in support of its various businesses. NRG's diversified load coupled with this asset portfolio enables the Company 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 its producer services business) to end use customers (through NRG's various sales channels). This scale, coupled with the Company's associated assets, gas system platform and people, create significant value across North America.
Plant Operations
As of December 31, 2025, the Company owns a diversified wholesale generation portfolio with approximately 12 GW of fossil fuel, and renewable generation capacity at 23 plants. 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, 2025:
(In MW)(a) | ||||||||||||||||||||||||||||||
| Type | Texas | East | West/Other(b) | Total | ||||||||||||||||||||||||||
| Natural gas | 5,069 | 80 | ||||||||||||||||||||||||||||
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Financial statements
data from SEC XBRL filings. Values are as-reported; restatements supersede originals. Values reported in .
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ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The discussion and analysis below has been organized as follows:
•Executive summary, including introduction and overview, business strategy, and changes to the business environment during the period, including environmental and regulatory matters;
•Known trends that may affect NRG’s results of operations and financial condition in the future;
•Results of operations; and
•Liquidity and capital resources including liquidity position, financial condition addressing credit ratings, material cash requirements and commitments, and other obligations.
As you read this discussion and analysis, refer to NRG’s condensed consolidated statements of operations to this Form 10-Q, which present the results of operations for the three months ended March 31, 2026 and 2025. Also refer to NRG’s 2025 Form 10-K, which includes detailed discussions of various items impacting the Company’s business, results of operations and financial condition, including: General section; Strategy section; Business Overview section, including how regulation, weather, and other factors affect NRG’s business; and Critical Accounting Estimates section.
Executive Summary
Introduction and Overview
NRG Energy, Inc., or NRG or the Company, provides electricity, natural gas, and smart-home technology solutions to approximately 8 million residential customers (comprised of 6 million retail energy and 2 million smart home), in addition to large commercial and industrial, data center and wholesale customers. Across North America, NRG is redefining customer’s experience with energy under brand names such as NRG, Reliant, Direct Energy, Green Mountain Energy, and Vivint. As of March 31, 2026, the Company’s core power and natural gas business consists of approximately 25 GW of competitive power generation, including approximately 13 GW from the LSP portfolio, and a natural gas portfolio that serves approximately 1,900 MMDth annually.
Strategy
NRG’s strategy is to maximize shareholder value by delivering integrated energy and smart home solutions, supported by an owned generation fleet and a diversified supply strategy. The Company generates power and sells electricity and natural gas to residential, commercial, industrial, and wholesale customers in the markets it serves. The Company also provides smart home security and automation services that deepen customer relationships and support long-term engagement. NRG operates a customer-first platform that promotes reliability and affordability amid rapid transformation in the energy sector. The Company is advancing opportunities to meet growing demand, including from data centers, other large load customers, and electrification. This includes (i) demand response and virtual power plants (“VPP”), which help manage costs and improve affordability for customers, (ii) completing the Texas Development Projects, (iii) long-term, contract-backed generation and related infrastructure, supported by strategic partnerships with equipment manufacturers and engineering, procurement, and construction companies, and (iv) increasing capacity at existing facilities. The Company’s differentiated model is built to meet North America’s evolving needs while delivering affordable, reliable solutions for customers and long-term growth for shareholders. This strategy is intended to generate recurring cash flow, strengthen earnings and cost competitiveness, and reduce risk and volatility.
To effectuate the Company’s strategy, NRG is focused on: (i) serving the energy needs of residential, commercial and industrial, and wholesale counterparties in competitive markets and optimizing on additional revenue opportunities through its multiple brands and channels; (ii) offering a variety of energy products and smart home products and services that are differentiated by innovative, value-additive features, premium service, integrated platforms, sustainability, loyalty/affinity programs, and affordability; (iii) excellence in operating performance of its assets; (iv) achieving the optimal mix of supply to serve its customer load requirements through a diversified supply strategy, including expanding its operational capacity to meet growing retail power supply needs; and (v) engaging in disciplined and transparent capital allocation.
In the first quarter of 2026, the operations acquired from LS Power were integrated into the Company’s existing segment structure, enhancing scale and portfolio optimization across the platform. In Texas, the Company’s generation portfolio is fully integrated with its retail load and in early 2026, the Company adopted an integrated strategy in the East, expanding this model across a broader geographic footprint. The integrated model strategically aligns generation and retail, enabling the Company to supply a portion of its retail customers with electricity from Company-owned assets, thereby reducing reliance to procure electricity from other institutions and intermediaries and supporting more stable earnings and cash flows, lower transaction costs, and reduced credit exposure. The integrated model also results in a reduction in actual and contingent collateral requirements, improving capital efficiency and further limiting transactions with third parties.
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Energy Regulatory Matters
The Company’s regulatory matters are described in the Company’s 2025 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 15, Regulatory Matters.
As participants in wholesale and retail energy markets and owners and operators of power plants, certain NRG entities are subject to regulation by various federal and state government agencies. These include the CFTC, FERC and the PUCT, as well as other public utility commissions in certain states where NRG’s generation or distributed generation assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO and RTO markets in which it participates. Likewise, certain NRG entities participating in the retail markets are subject to rules and regulations established by the states and provinces in which NRG entities are licensed to sell at retail. NRG must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where NRG operates.
NRG’s operations within the ERCOT footprint are not subject to rate regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by the PUCT.
State and Provincial Energy Regulation
Maryland Legislation — On May 9, 2024, Maryland Governor Wes Moore signed Senate Bill (“SB”) 1 into law, which restricts the competitive retail electric and natural gas market in Maryland, affecting residential customers but not commercial and industrial customers. Key provisions of the law took effect on January 1, 2025. The legislation imposes a price cap on residential contracts tied to a trailing 12-month historical average of utility rates, with only a limited exception for renewable power products. Renewable products must now have their price pre-approved by the Maryland Public Service Commission and source their renewable electricity certificates from within the PJM region. The law also requires that any variable-price contract not contain a change in price more than once a year, except time-of-use contracts, and limits contract terms to 12 months. It requires affirmative consent for the renewal of customer contracts for renewable power products. The law also imposes licensing requirements on energy salespeople. While the law states that it does not impair existing contracts, the Maryland Public Service Commission has ruled that grandfathering of existing contracts will end as of December 31, 2025, and that suppliers must issue separate bills for their charges for all new and renewing contracts as of January 1, 2026. On October 1, 2024, Green Mountain Energy Company, NRG’s renewable electricity provider, along with a retail trade association to which NRG belongs, filed a lawsuit in federal court challenging the constitutionality of SB 1. On November 18, 2024, the trial court denied the plaintiffs’ motion for a preliminary injunction. The plaintiffs, including Green Mountain, filed an appeal to this denial in the Court of Appeals for the Fourth Circuit and oral argument occurred on October 24, 2025. The appeal is pending.
Regional Regulatory Developments
NRG is affected by rule/tariff changes that occur in the ISO regions. For further discussion on regulatory developments, see Item 1 — Note 15, Regulatory Matters, to the condensed consolidated financial statements.
ERCOT/PUCT
PUCT’s Actions with Respect to Wholesale Pricing and Market Design — The PUCT continues to analyze and implement multiple options for promoting increased reliability in the wholesale electric market, including the adoption of a reliability standard for resource adequacy and market-based mechanisms to achieve this standard. The Commission adopted a reliability standard that became effective in September 2024.
In 2023, the Texas Legislature authorized implementation of the Performance Credit Mechanism (“PCM”), which will measure real-time contribution to system reliability and provide compensation for resources to be available, subject to certain “guardrails” such as an absolute annual net cost cap, as part of its adoption of the PUCT Sunset Bill (House Bill 1500). In December 2024, the PUCT decided to shelve implementation of the PCM indefinitely. The Texas Legislature also directed the PUCT to implement a new ancillary service called Dispatchable Reliability Reserve Service (“DRRS”) to further increase ERCOT’s capability to manage net load variability and firming requirements for new generation resources which penalize poor performance during periods of low grid reserves. In November 2025, ERCOT published an updated design proposal for DRRS that includes the ability for the PUCT to configure it to support resource adequacy through stronger financial incentives for dispatchable thermal generation. The PUCT will evaluate the final design of DRRS as part of the review of the reliability standard in 2026. The PUCT adopted a final rule to implement the firming requirement in December 2025, which requires new generation resources with signed interconnection agreements on or after January 1, 2027, to acquire additional capacity to meet a minimum requirement during low reserve hours on the ERCOT system.
Texas Energy Fund — Through SB 2627, the Texas Legislature created the TEF, to provide grants and low-interest loans (3%) to incentivize the development of more dispatchable generation and smaller backup generation in ERCOT. The PUCT also adopted a rule for the completion bonus grant program in April 2024, which provides for opportunities for grants of $120,000 per MW for dispatchable generation projects interconnected before June 1, 2026, or $80,000 per MW for dispatchable generation projects interconnected on or after June 1, 2026 but before June 1, 2029, subject to performance requirements. The
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89th Texas Legislature passed SB 2268, which separated the 10,000 MW collective cap on the ERCOT loan and grant programs resulting in a 10,000 MW cap for the loan program and a separate 10,000 MW cap for the completion bonus grant program.
NRG, through its subsidiaries, filed and received approval from the PUCT for loan proceeds for three separate projects, totaling more than 1,500 MWs of capacity. Specifically, on July 31, 2025, the Company entered into a $216 million loan agreement with the PUCT under the TEF to support the development of T.H. Wharton, a 415 MW facility. On December 12, 2025, the PUCT approved the notice of eligibility for the completion bonus grant for T.H. Wharton. On September 26, 2025, the Company entered into a $562 million loan agreement with the PUCT under the TEF to support the development of Cedar Bayou 5, a 689 MW facility. Lastly, on November 20, 2025, the Company entered into a $370 million loan agreement with the PUCT under the TEF to support the development of Greens Bayou 6, a 443 MW facility. All three projects are currently under construction. Commercial operations at T.H. Wharton is expected by the end of May 2026.
Senate Bill 6 — On June 20, 2025, the Governor of Texas signed SB 6 into law, which includes various provisions that concern how both ERCOT, transmission and distribution utilities, and power generation companies plan for and serve large loads (defined as 75 MWs and above) in the ERCOT market. SB 6 improves load forecasting accuracy by requiring criteria for inclusion into the forecast and by requiring financial commitments upon a request for a large load customer seeking interconnection to begin engineering studies. In addition, SB 6 includes processes by which large loads should be required or incentivized to curtail their operations. At the same time, SB 6 establishes a PUCT regulatory procedure to minimize potential reliability and stranded-cost impacts that may be associated with new large load co-locations with power generators that were interconnected to ERCOT and operating as stand-alone generators as of September 1, 2025. Generators connected to the grid after this date are exempt from this procedure. Finally, SB 6 requires the PUCT to investigate revising the cost allocation and rate design that governs the ERCOT transmission system. The PUCT rulemaking process for these components of SB 6 is in progress. On March 27, 2026, the PUCT published its proposed rule relating to large load interconnection standards, which establishes the standards and criteria to interconnect a large load customer to the ERCOT system, as well as the financial security large load customers would need to provide. A final rule is anticipated in the third quarter of 2026. ERCOT is also developing revisions to the interconnection study process to more efficiently review large load interconnection requests.
PJM
Revisions to PJM Locational Deliverability Area (“LDA”) Reliability Requirement — PJM delayed publication of the Base Residual Auction (“BRA”) results for the 2024/2025 delivery year and filed at FERC to revise the definition of the LDA Reliability Requirement in the Tariff to allow PJM to exclude certain resources from the calculation of the LDA Reliability Requirement, which FERC accepted on February 21, 2023. Multiple parties, including NRG, filed for rehearing and subsequently appealed to the Court of Appeals for the Third Circuit. On March 12, 2024, the court vacated the portion of the FERC orders permitting application of the revised LDA Reliability Requirement to the 2024/2025 BRA. Following additional proceedings, FERC directed PJM to recalculate the BRA results using the original LDA Reliability Requirements and to rerun the Third Incremental Auction, and PJM published revised results on May 8, 2024, and May 23, 2024, respectively. On July 9, 2024, FERC denied a related complaint filed on April 22, 2024 (the “April 2024 Complaint”) which was appealed to the Court of Appeals for the D.C. Circuit on November 5, 2024. On January 13, 2026, the Court of Appeals for the D.C. Circuit issued a decision vacating FERC’s order denying the April 2024 Complaint and remanding the case to FERC for a ruling on the substance of the complaint. The remanded complaint is pending at FERC.
PJM Base Residual Auction Revisions and Delay — In November 2024, at PJM’s request, FERC approved delays to future BRAs. The 2028/2029 BRA is scheduled to occur in May 2026 and is the last delayed auction affected.
PJM’s Reforms to Large Load Additions — On September 15, 2025, PJM began a formal stakeholder process called the Critical Issue Fast Path (“CIFP”) to address needed reforms to accommodate large load additions. On January 16, 2026, the National Energy Dominance Council within the White House released a Statement of Principles, signed by all 13 governors in the PJM region, urging PJM to address revenue certainty for new generation through an auction process for new capacity, allocate the costs of these new resources to data centers, improve load forecasting, and accelerate ongoing generation interconnection studies. Also on January 16, 2026, the PJM Board issued a decisional letter on the CIFP process. The Board letter directed PJM staff to implement changes to load forecasting, implement a bring your own new generation program and associated expedited interconnection track, initiate immediately a Reliability Backstop Auction to obtain commitments of additional generation for a longer term, and undertake a holistic review of the PJM markets to analyze how they can evolve to provide appropriate incentives for investment and performance. On February 27, 2026, PJM made two filings at FERC. In its first filing, PJM proposed an expedited interconnection track for up to ten qualified large load projects. This filing is pending at FERC. In its second filing, PJM proposed an extension of the price cap and price floor for all capacity auctions through the 2028/2029 and 2029/2030 delivery years. On April 28, 2026, FERC approved PJM’s second filing to extend the price cap and price floor.
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On April 10, 2026, PJM published a Reliability Backstop Procurement proposal in response to the January 16, 2026 Board directive. PJM proposes a one-time, transitional procurement of capacity in two-stages. An initial process for facilitating bilateral contracts between large loads and eligible supply, beginning in September 2026 and ending in March 2027, followed by a central procurement process to commence in March 2027. PJM expects to file at FERC to implement these changes in June 2026, following an abbreviated stakeholder process. The implementation of these market changes could have material impacts on the PJM market.
Consumer Advocates Complaint — On April 14, 2025, various state consumer advocates filed a complaint with FERC asking FERC to reprice the 2025/2026 PJM capacity auction results. If FERC were to grant the request, the capacity prices for the 2025/2026 delivery year would be expected to change. The complaint is pending at FERC.
Indian River RMR Proceeding — On June 29, 2021, Indian River notified PJM that it intended to retire Unit 4. PJM identified reliability violations resulting from the proposed deactivation of Unit 4. The Company filed a cost based RMR rate schedule at FERC. The Company reached settlement with a number of the intervening parties and the settlement agreement was filed. On January 16, 2025, FERC issued an order approving the settlement agreement. Indian River Unit 4 retired on February 23, 2025. On May 19, 2025, Maryland Office of People’s Counsel filed an appeal to the Court of Appeals for the Fourth Circuit of FERC’s denial on its request for rehearing. On August 22, 2025, NRG filed a motion to transfer venue. On November 12, 2025, the motion to transfer venue was granted and the appeal was transferred to the Court of Appeals for the D.C. Circuit. The appeal is pending.
Other Regulatory Matters
From time to time, NRG entities may be subject to examinations, investigations and/or enforcement actions by federal, state and provincial licensing and regulatory agencies and may face the risk of penalties for violation of financial services, consumer protections and other applicable laws and regulations.
Environmental Regulatory Matters
NRG is subject to numerous environmental laws in the development, construction, ownership and operation of power plants. These laws generally require that governmental permits and approvals be obtained before construction and maintained during operation of power plants. In general, the electric generation industry has faced increasingly stringent requirements regarding air quality, GHG emissions, combustion byproducts, water use and discharge, and threatened and endangered species including several rules promulgated in 2024. Future laws may require the addition of emissions controls or other environmental controls or to impose additional restrictions the operations of the Company’s facilities including unit retirements or impose obligations related to historic coal ash use, storage and disposal. At the federal level, the President has issued several Executive Orders that indicate that the current administration intends to relax or rescind some previously promulgated regulations. The EPA has proposed several and finalized some rules that relax and/or rescind regulations previously promulgated. Complying with environmental laws often involves specialized human resources and significant capital and operating expenses, as well as occasionally curtailing operations. 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.
Several regulations that affect the Company have been and continue to be revised by the EPA, including requirements regarding coal ash, GHG emissions, NAAQS revisions and implementation and effluent limitation guidelines. NRG will evaluate the impact of these regulations as they are revised but cannot fully predict the impact of each until anticipated revisions, legal challenges and reconsiderations are resolved. The Company’s environmental matters are described in the Company’s 2025 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Note 16, Environmental Matters, to the condensed consolidated financial statements of this Form 10-Q and as follows.
Air
The CAA and related regulations (as well as similar state and local requirements) have the potential to affect air emissions, operating practices and pollution control equipment required at power plants. Under the CAA, the EPA sets NAAQS for certain pollutants including SO2, ozone, and PM2.5. Many of the Company’s facilities are located in or near areas that are classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS may become more stringent. In March 2024, the EPA increased the stringency of the PM2.5 NAAQS but in November 2025, the EPA asked the DC Circuit to vacate the March 2024 rule. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent requirements could require the installation of additional emissions control equipment at some NRG facilities or retiring of units if installing such controls is not economic. Significant changes to air regulatory programs affecting the Company are described below.
CPP/ACE Rules — The attention in recent years on GHG emissions has resulted in federal and state regulations. In 2019, the EPA promulgated the ACE rule, which rescinded the CPP, which had sought to broadly regulate CO2 emissions from the
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power sector. On January 19, 2021, the D.C. Circuit vacated the ACE rule (but on February 22, 2021, at the EPA’s request, stayed the issuance of the portion of the mandate that would vacate the repeal of the CPP). On June 30, 2022, the U.S. Supreme Court held that the “generation shifting” approach in the CPP exceeded the powers granted to the EPA by Congress. On May 9, 2024, the EPA promulgated a rule that repealed the ACE rule and significantly revised the manner in which new combustion-turbine and existing steam EGU’s GHG emissions would be regulated including capturing and storing/sequestering CO2 in some instances. This rule has been challenged by numerous parties in the D.C. Circuit including 27 states with 22 states intervening in support of the rule. The D.C. Circuit held oral arguments related to this rule in December 2024. In February 2025, the court granted a motion the DOJ filed asking the court to hold proceedings in abeyance while the EPA evaluates the rule. On June 17, 2025, the EPA proposed to repeal all GHG emission standards for fossil fuel-fired power plants under Section 111 of the CAA. The EPA is proposing to conclude that GHG emissions from domestic fossil fuel-fired EGUs do not contribute to dangerous air pollution at a level sufficient to invoke the EPA’s authority under CAA Section 111. In addition to its primary proposal to repeal all GHG emission standards for the power sector promulgated in both 2015 and 2024, the EPA has included an alternative proposal to repeal just specific portions. On February 18, 2026, the EPA rescinded the 2009 GHG Endangerment Finding related to motor vehicle emissions. Although this rescission does not directly alter the GHG regulations related to power plants, the Company believes that the EPA may amend such regulations this year.
CSAPR — On March 15, 2023, the EPA signed and released a prepublication version of a final rule that sought to significantly revise the CSAPR to address the good-neighbor obligations of the 2015 ozone NAAQS for 23 states (a Federal Implementation Plan or “FIP”) after earlier having disapproved numerous state plans to address the issue. Several states, including Texas, challenged the EPA’s disapproval of their state plans. On May 1, 2023, the Fifth Circuit stayed the EPA’s disapproval of Texas’s and Louisiana’s state plans, which disapprovals are a condition precedent to the EPA imposing its plan on Texas and Louisiana. On March 25, 2025, the Fifth Circuit upheld the EPA’s disapproval of Texas’s and Louisiana’s state plans but did not address the FIP. On May 9, 2025, Texas and other parties petitioned the Fifth Circuit for a rehearing with the whole court. On March 13, 2026, the Fifth Circuit issued a revised opinion vacating and remanding the EPA’s disapproval of Texas’s interstate transport plan. On June 5, 2023, the EPA promulgated the FIP. On June 27, 2024, the U.S. Supreme Court stayed the FIP in the 11 states where the rule had not already been stayed. On April 14, 2025, the D.C. Circuit granted the EPA’s request to hold the legal challenges in abeyance while the EPA revisits the rule. On January 30, 2026, the EPA proposed a Phase 1 reconsideration rule covering Alabama, Arizona, Iowa, Kansas, Kentucky, Minnesota, Mississippi, Nevada, New Mexico and Tennessee. The EPA intends to address additional states in a separate action. The Company cannot predict the outcome of the legal challenges to the various state disapprovals and the final rule promulgated on June 5, 2023.
Regional Haze — In May 2023, the EPA proposed to withdraw the existing Texas Sulfur Dioxide Trading Program and replace it with unit-specific SO2 limits for 12 units in Texas to address requirements to improve visibility at National Parks and Wilderness areas. The Company does not expect this proposal to be finalized during the current U.S. presidential administration. On December 5, 2025, the EPA approved Texas’s plans to address the Regional Haze rule.
MATS — On May 7, 2024, the EPA promulgated a final rule that amends the MATS rule by, among other things, increasing the stringency of the filterable particulate matter standard at coal-burning units. The deadline for complying with this more stringent standard had been 2027. On April 8, 2025, the President signed a Proclamation that creates a 2-year exemption for compliance beginning on July 8, 2027 and ending on July 8, 2029 for certain coal units including those owned by the Company. Twenty-three states have challenged this rule in the D.C. Circuit. On June 17, 2025, the EPA proposed to repeal the majority of the 2024 final rule amending the MATS rule. On February 24, 2026, the EPA promulgated a final rule repealing the majority of the 2024 rule amending the MATS rule.
Water
The Company is required under the Clean Water Act to comply with intake and discharge requirements, requirements for technological controls and operating practices. As with air quality regulations, federal and state water regulations have become more stringent and imposed new requirements.
ELG — In 2015, the EPA revised the 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 October 13, 2020, the EPA amended the 2015 ELG rule by: (i) altering the stringency of certain limits for FGD wastewater; (ii) relaxing the zero-discharge requirement for bottom ash transport water; and (iii) changing several deadlines. In 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 that have coal-fired units in Texas. On May 9, 2024, the EPA promulgated a rule that again revises the ELG by, among other things, further restricting the discharge of (i) FGD wastewater, (ii) bottom ash transport water, and (iii) combustion residual leachate. The rule was challenged in numerous courts, but the cases were consolidated in the U.S. Court of Appeals for the Eighth Circuit. The outcome of the legal challenges is uncertain. On February 19, 2025, the DOJ filed a motion asking the court to hold proceedings in abeyance while the U.S. presidential administration evaluates the rule, which the court granted. On December
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31, 2025, the EPA promulgated a rule that extends several deadlines and provides greater flexibility regarding decisions to invest in more stringent controls.
Byproducts
In 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. On August 21, 2018, the D.C. Circuit found, among other things, that the EPA had not adequately regulated unlined ponds and legacy surface impoundments. On August 28, 2020, the EPA finalized “A Holistic Approach to Closure Part A: Deadline to Initiate Closure,” which amended the April 2015 Rule to address the August 2018 D.C. Circuit decision and extend some of the deadlines. On November 12, 2020, the EPA finalized “A Holistic Approach to Closure Part B: Alternative Demonstration for Unlined Surface Impoundments,” which further amended the April 2015 Rule to, among other things, provide procedures for requesting approval to operate existing ash impoundments with an alternate liner. On May 8, 2024, the EPA promulgated a rule that establishes requirements for: (i) inactive (or legacy) surface impoundments at inactive facilities and (ii) CCR management units (regardless of how or when the CCR was placed) at regulated facilities. The rule also creates an obligation to conduct site assessments (at all active and certain inactive facilities) to determine whether CCR management units are present. On February 10, 2026, the EPA promulgated a rule extending certain deadlines in the 2024 rule. On April 13, 2026, the EPA proposed further amendments to the CCR that if finalized would provide industry greater compliance flexibility. The rule has been challenged in the D.C. Circuit and the outcome of the legal challenges is uncertain.
Domestic Site Remediation Matters
Under certain federal, state and local environmental laws, a current or previous owner or operator of a facility, including an electric generating facility, may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products. NRG may be responsible for property damage, personal injury and investigation and remediation costs incurred by a party in connection with hazardous material releases or threatened releases. These laws impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and the courts have interpreted liability under such laws to be strict (without fault) and joint and several. Cleanup obligations can often be triggered during the closure or decommissioning of a facility, in addition to spills during its operations.
Regional Environmental Developments
Ash Regulation in Illinois — On July 30, 2019, Illinois enacted legislation that required the state to promulgate regulations regarding coal ash at surface impoundments. On April 15, 2021, the state promulgated the implementing regulation, which became effective on April 21, 2021. NRG has applied for initial operating permits and construction permits (for closure and retrofits) as required by the regulation and is waiting for most of its permits to be issued by the Illinois EPA.
Houston Nonattainment for 2008 Ozone Standard — In 2022, the EPA changed the Houston area’s classification from Serious to Severe nonattainment for the 2008 Ozone Standard. Accordingly, Texas is required to develop a new control strategy and submit it to the EPA.
Virginia Rejoining the Regional Greenhouse Gas Initiative (“RGGI”) — On February 20, 2026, Virginia enacted legislation to rejoin the RGGI. Virginia is working on promulgating the implementing regulations and is seeking to require compliance beginning on July 1, 2026.
Significant Events
The following significant events have occurred during 2026 as further described within this Management’s Discussion and Analysis and the condensed consolidated financial statements:
Acquisition of LSP Portfolio
On January 30, 2026, NRG completed the acquisition of the LSP Portfolio from LS Power. The acquisition doubles NRG’s generation capacity with the addition of 18 natural gas-fired and dual fuel facilities totaling approximately 13 GW. In addition, NRG acquired CPower, a leading demand response platform, which operates in all the country’s deregulated energy markets and has more than 2,000 commercial and industrial customers. The consideration consisted of 24.25 million shares of NRG common stock and $6.4 billion in cash, plus preliminary working capital and certain other adjustments of $483 million. The Company funded the cash consideration using a portion of the net proceeds of $4.4 billion from the 5.750% 2034 Senior Notes, the 2036 Senior Notes, Senior Secured First Lien Notes, due 2030 and the Senior Secured First Lien Notes, due 2035 and proceeds of $2.5 billion from the Company’s Revolving Credit Facility. For further discussion, see Note 4, Acquisitions.
Capital Allocation
During the three months ended March 31, 2026, the Company completed $481 million of share repurchases at an average price of $161.16 per share. Through April 30, 2026, an additional $338 million of share repurchases were executed at an average price of $156.52 per share. See Note 9, Changes in Capital Structure for additional discussion.
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In the first quarter of 2026, NRG increased the annual common stock dividend to $1.90 from $1.76 per share, representing an 8% increase from 2025. The Company targets an annual dividend growth rate of 7-9% per share in subsequent years.
Term Loan B Incurrence
On April 28, 2026, the Company and APX Group LLC, as borrowers, and certain of the Company’s subsidiaries, as guarantors, entered into the Sixteenth Amendment to the Credit Agreement. For further discussion, see Note 7, Long-term Debt and Finance Leases.
Issuance of Unsecured Notes and Secured Notes
On April 28, 2026, the Company issued $2.1 billion in aggregate principal amount of the New Unsecured Notes. The New Unsecured Notes are senior unsecured obligations of the Company and are guaranteed by its wholly-owned U.S. subsidiaries that guarantee the loans under the Senior Credit Facility. For further discussion, see Note 7, Long-term Debt and Finance Leases.
On April 28, 2026, the Company also issued $500 million aggregate principal amount of the New 2031 Notes. The New 2031 Notes are senior secured obligations of the Company and are guaranteed by its wholly-owned U.S. subsidiaries that guarantee the loans under the Senior Credit Facility. For further discussion, see Note 7, Long-term Debt and Finance Leases.
Bilateral Letter of Credit Facilities
In January and February 2026, the Company and certain of its subsidiaries, as guarantors, entered into amendments to its existing bilateral letter of credit facilities to increase the size of its bilateral credit facilities by $410 million and $90 million, respectively, to provide additional liquidity. As of March 31, 2026, $739 million was issued under these facilities.
Lightning Tender Offer and Redemption
On April 14, 2026, Lightning commenced the Tender Offer. For further discussion, see Note 7, Long-term Debt and Finance Leases.
Further, pursuant to the terms of the Lightning Indenture, on April 28, 2026, Lightning issued the Redemption to redeem the remaining $5 million aggregate principal amount of the Lightning 2032 Notes at a redemption price of 101.375% (plus accrued and unpaid interest to, but excluding, the redemption date). For further discussion, see Note 7, Long-term Debt and Finance Leases.
Trends Affecting Results of Operations and Future Business Performance
The Company’s trends are described in the Company’s 2025 Form 10-K in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Business Environment, except for the update below:
Geopolitical Developments — The ongoing geopolitical conflicts, including hostilities with Iran and conflicts in the Middle East, have contributed to elevated and volatile oil prices and could, over time, put upward pressure on U.S. natural gas. Prolonged market volatility could result in increased collateral requirements and heighten counterparty credit exposure under NRG’s hedging arrangements.
Changes in Accounting Standards
See Note 2, Summary of Significant Accounting Policies, for a discussion of recent accounting developments.
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Consolidated Results of Operations
The following table provides selected financial information for the Company:
| Three months ended March 31, | |||||||||||||||||||||||||||||
| (In millions) | 2026 | 2025 | Change | ||||||||||||||||||||||||||
| Revenue | |||||||||||||||||||||||||||||
| Retail revenue | $ | 9,500 | $ | 8,216 | $ | 1,284 | |||||||||||||||||||||||
Energy revenue(a) | 475 | 245 | 230 | ||||||||||||||||||||||||||
Capacity revenue(a) | 239 | 47 | 192 | ||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | (42) | (15) | (27) | ||||||||||||||||||||||||||
| Contract amortization | 6 | (5) | 11 | ||||||||||||||||||||||||||
Other revenues(a)(b) | 78 | 97 | (19) | ||||||||||||||||||||||||||
| Total revenue | 10,256 | 8,585 | 1,671 | ||||||||||||||||||||||||||
| Operating Costs and Expenses | |||||||||||||||||||||||||||||
| Cost of fuel | 444 | 334 | (110) | ||||||||||||||||||||||||||
Purchased energy and other cost of sales(c) | 7,697 | 6,182 | (1,515) | ||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | 163 | (346) | (509) | ||||||||||||||||||||||||||
Contract and emissions credit amortization(c) | 17 | 25 | 8 | ||||||||||||||||||||||||||
| Operations and maintenance | 433 | 288 | (145) | ||||||||||||||||||||||||||
| Other cost of operations | 104 | 78 | (26) | ||||||||||||||||||||||||||
| Cost of operations (excluding depreciation and amortization shown below) | 8,858 | 6,561 | (2,297) | ||||||||||||||||||||||||||
| Depreciation and amortization | 432 | 326 | (106) | ||||||||||||||||||||||||||
| Selling, general and administrative costs (excluding amortization of customer acquisition costs of $87 and $65, respectively, which are included in depreciation and amortization shown separately above) | 593 | 549 | (44) | ||||||||||||||||||||||||||
| Acquisition-related transaction and integration costs | 45 | 8 | (37) | ||||||||||||||||||||||||||
| Total operating costs and expenses | 9,928 | 7,444 | (2,484) | ||||||||||||||||||||||||||
| Loss on sale of assets | — | (7) | 7 | ||||||||||||||||||||||||||
| Operating Income | 328 | 1,134 | (806) | ||||||||||||||||||||||||||
| Other Income/(Expense) | |||||||||||||||||||||||||||||
| Other income, net | 40 | 14 | 26 | ||||||||||||||||||||||||||
| Interest expense | (285) | (163) | (122) | ||||||||||||||||||||||||||
| Total other expense | (245) | (149) | (96) | ||||||||||||||||||||||||||
| Income Before Income Taxes | 83 | 985 | (902) | ||||||||||||||||||||||||||
| Income tax (benefit)/expense | (42) | 235 | 277 | ||||||||||||||||||||||||||
| Net Income | $ | 125 | $ | 750 | $ | (625) | |||||||||||||||||||||||
(a)Includes gains and losses from financially settled transactions
(b)Includes trading gains and losses and ancillary revenues
(c)Includes amortization of SO2 and NOx credits and excludes amortization of RGGI credits
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Management’s discussion of the results of operations for the three months ended March 31, 2026 and 2025
Electricity Prices
The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the three months ended March 31, 2026 and 2025:
| Average on Peak Power Price ($/MWh) | |||||||||||||||||
| Three months ended March 31, | |||||||||||||||||
| Region | 2026 | 2025 | Change % | ||||||||||||||
| Texas | |||||||||||||||||
ERCOT - Houston(a) | $ | 29.03 | $ | 33.26 | (13) | % | |||||||||||
ERCOT - North(a) | 27.46 | 35.38 | (22) | % | |||||||||||||
| East | |||||||||||||||||
NY J/NYC(b) | $ | 134.66 | $ | 110.45 | 22 | % | |||||||||||
NEPOOL(b) | 122.69 | 108.83 | 13 | % | |||||||||||||
COMED (PJM)(b) | 59.83 | 42.21 | 42 | % | |||||||||||||
PJM - West Hub(b) | 103.38 | 60.16 | 72 | % | |||||||||||||
PJM - APS(b) | 102.74 | 57.52 | 79 | % | |||||||||||||
PJM - DOMINION(b) | 110.81 | 64.33 | 72 | % | |||||||||||||
| West | |||||||||||||||||
MISO - Louisiana Hub(b) | $ | 50.32 | $ | 47.14 | 7 | % | |||||||||||
CAISO - SP15(b) | 22.05 | 26.46 | (17) | % | |||||||||||||
(a)Average on peak power prices based on real time settlement prices as published by the respective ISOs
(b)Average on peak power prices based on day ahead settlement prices as published by the respective ISOs
Natural Gas Prices
The following table summarizes the average Henry Hub natural gas price for the three months ended March 31, 2026 and 2025:
| Three months ended March 31, | |||||||||||||||||
| 2026 | 2025 | Change % | |||||||||||||||
($/MMBtu) | $ | 5.04 | $ | 3.65 | 38 | % | |||||||||||
Gross Margin
The Company calculates gross margin in order to evaluate operating performance as revenues less cost of fuel, purchased energy and other costs of sales, mark-to-market for economic hedging activities, contract and emissions credit amortization and depreciation and amortization.
Economic Gross Margin
In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company’s presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company’s management. Economic gross margin is defined as the sum of retail revenue, energy revenue, capacity revenue and other revenue, less cost of fuel, purchased energy and other cost of sales. Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emissions credit amortization, depreciation and amortization, operations and maintenance, or other cost of operations.
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The following tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended March 31, 2026 and 2025:
| Three months ended March 31, 2026 | ||||||||||||||||||||||||||||||||||||||
($ In millions) | Texas(a) | East(a) | West/Other | Vivint Smart Home | Corporate/Eliminations | Total | ||||||||||||||||||||||||||||||||
| Retail revenue | $ | 2,335 | $ | 5,737 | $ | 862 | $ | 578 | $ | (12) | $ | 9,500 | ||||||||||||||||||||||||||
| Energy revenue | 8 | 467 | — | — | — | 475 | ||||||||||||||||||||||||||||||||
| Capacity revenue | — | 239 | — | — | — | 239 | ||||||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | — | (44) | — | — | 2 | (42) | ||||||||||||||||||||||||||||||||
| Contract amortization | — | 6 | — | — | — | 6 | ||||||||||||||||||||||||||||||||
Other revenue(b) | 50 | 27 | 2 | — | (1) | 78 | ||||||||||||||||||||||||||||||||
| Total revenue | 2,393 | 6,432 | 864 | 578 | (11) | 10,256 | ||||||||||||||||||||||||||||||||
| Cost of fuel | (214) | (229) | (1) | — | — | (444) | ||||||||||||||||||||||||||||||||
Purchased energy and other cost of sales(c)(d)(e) | (1,494) | (5,442) | (710) | (52) | 1 | (7,697) | ||||||||||||||||||||||||||||||||
| Mark-to-market for economic hedging activities | (51) | (56) | (54) | — | (2) | (163) | ||||||||||||||||||||||||||||||||
| Contract and emissions credit amortization | (2) | (14) | (1) | — | — | (17) | ||||||||||||||||||||||||||||||||
| Depreciation and amortization | ||||||||||||||||||||||||||||||||||||||
Recent insider activity
| Date | Insider | Role | Action | Shares | Price | Value |
|---|---|---|---|---|---|---|
| 2026-09-08 | Spencer Gerald Alfred | SVP & Chief Accounting Officer | Sell | -1,580 | $120.93 | -$191,069 |
Source: SEC Form 4 filings.
Next expected filings
- ~2027-02-23 10-K expected by 2027-02-27 (in 106 days)
- ~2027-05-04 10-Q expected by 2027-05-07 (in 176 days)
- ~2027-08-02 10-Q expected by 2027-08-05 (in 266 days)
- ~2027-11-04 10-Q expected by 2027-11-07 (in 360 days)
Predicted from historical filing cadence; not an SEC commitment.
Recent SEC filings
- 2026-11-09 8-K Earnings Release
- 2026-08-04 8-K Earnings Release; Financial Statements and Exhibits
- 2026-08-04 10-Q Quarterly Report
- 2026-07-15 8-K Other Events
- 2026-05-21 8-K Officer/Director Change; Regulation FD Disclosure; Financial Statements and Exhibits
- 2026-05-06 8-K Earnings Release; Financial Statements and Exhibits
- 2026-05-06 10-Q Quarterly Report
- 2026-04-30 8-K/A Officer/Director Change; Financial Statements and Exhibits
- 2026-04-30 S-8 Employee Benefit Plan Registration
- 2026-04-28 8-K Material Agreement Entered; Material Financial Obligation; Regulation FD Disclosure; Financial Statements and Exhibits
- 2026-04-07 8-K Officer/Director Change
- 2026-03-04 8-K Material Agreement Entered; Other Events; Financial Statements and Exhibits
- 2026-03-02 8-K Other Events; Financial Statements and Exhibits
- 2026-02-24 10-K Annual Report
- 2026-02-24 8-K Earnings Release; Financial Statements and Exhibits