WILLIAMS COMPANIES, INC. (WMB)

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

Williams is an energy company committed to being the leader in providing infrastructure that safely delivers natural gas products to reliably fuel the clean energy economy. Its operations are located in the United States.

Williams’ interstate natural gas pipeline strategy is to create value by maximizing the utilization of its pipeline capacity by providing high-quality, low-cost transportation of natural gas to large and growing markets. Williams’ gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC. As such, Williams’ rates and charges for the transportation of natural gas in interstate commerce; the extension, expansion, or abandonment of jurisdictional facilities; and accounting, among other things, are subject to regulation. The rates are established primarily through the FERC’s ratemaking process, but Williams may also negotiate rates with its customers pursuant to the terms of its tariffs and FERC policy. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of the cost of service is recovered through firm capacity reservation charges in transportation rates.

The ongoing strategy of Williams’ midstream operations is to safely and reliably operate large-scale midstream infrastructure where its assets can be fully utilized and drive low per-unit costs. Williams focuses on consistently attracting new business by providing highly reliable service to its customers. These services include natural gas gathering and processing, treating, compression and storage; NGL fractionation, transportation and storage; and crude oil production handling and transportation, as well as marketing services for NGL, crude oil, and natural gas.

Consistent with the manner in which Williams’ CODM evaluates performance and allocates resources, Williams’ operations are conducted, managed, and presented within the following reportable segments: Transmission, Power & Gulf; Northeast G&P; West; and Gas & NGL Marketing Services. All remaining business activities, including upstream operations and corporate activities, are included in Other. See Note 1 – Description of Business and Basis of Presentation for a full description of each segment.

Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity relates to Williams’ current continuing operations and should be read in conjunction with the financial statements and combined notes thereto of this Form 10-Q and the Annual Report on Form 10-K for the year ended December 31, 2025, as filed with the SEC on February 24, 2026.

Dividends

In March 2026, Williams paid a regular quarterly dividend of $0.525 per share.

Overview of Three Months Ended March 31, 2026

Net income (loss) attributable to The Williams Companies, Inc. for the three months ended March 31, 2026, increased $174 million compared to the three months ended March 31, 2025. Further discussion of the results is found in this report in the Results of Operations.

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Recent Developments

Transco FERC Rate Case Filing

On August 30, 2024, Transco filed a general rate case with the FERC for an overall increase in rates and to comply with the terms of the settlement of its prior rate case. On September 30, 2024, the FERC issued an order accepting and suspending Transco’s general rate filing to be effective March 1, 2025, subject to refund and the outcome of hearing procedures established by the FERC. The order also accepted rate decreases for certain services to be effective as of October 1, 2024. During the third quarter of 2025, Transco reached an agreement in principle with its customers and the other participants to settle all aspects of the rate case and has accrued a related liability for rate refunds. Transco filed with the FERC in October 2025 for approval of the settlement. On December 30, 2025, the FERC approved the settlement which became effective March 1, 2026. The refunds were paid in April 2026.

Sale of Mid-Continent Gathering Assets

In the first quarter of 2026, Williams’ closed on the sale of certain gas gathering assets in the Mid-Continent region. These operations were designated as held for sale at December 31, 2025 and an impairment, within the West segment, was recognized. See Note 8 – Fair Value Measurements and Guarantees.

Sale of South Mansfield Upstream Interests

In January 2026, Williams closed on the sale of its interests in certain upstream ventures in the South Mansfield area of the Haynesville Shale region, included in Other, for consideration of $398 million with additional contingent consideration to possibly be received through 2029. Upon closing, Williams recognized a gain of $182 million in the first quarter of 2026. See Note 3 – Divestitures.

Expansion Project Updates

Expansion projects placed into service for the current year are described below. Ongoing major expansion projects are discussed later in Company Outlook.

Transmission, Power & Gulf

Naughton Coal-to-Gas Conversion

The project involves an expansion of NWP’s existing natural gas transmission system to provide year-round transportation capacity to a power plant in southwest Wyoming. NWP placed the project into service in April 2026, increasing NWP’s capacity by 98 Mdth/d.

Company Outlook

Williams’ strategy is to provide a large-scale, reliable, and clean energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. Williams accomplishes this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. Williams continues to maintain a strong commitment to safety, environmental stewardship including seeking opportunities for renewable energy ventures, operational excellence, and customer satisfaction. Williams believes that accomplishing these goals will position it to deliver safe, reliable, clean energy services to its customers and an attractive return to shareholders. Williams’ business plan for 2026 includes a continued focus on earnings and cash flow growth.

In 2026, Williams’ operating results are expected to benefit from the continued growth in the Transmission, Power & Gulf segment, primarily reflecting the impacts of the Socrates Power Innovation project, as well as numerous expansion projects at Transco and the Gulf of America. Growth in 2026 will benefit from a full year of the Louisiana Energy Gateway expansion project as well as expected increases in Haynesville Shale volumes.

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Additionally, Williams expects higher gathering and processing results in the Northeast. These increases are partially offset by the divestiture of the South Mansfield upstream joint venture, and lower expected Eagle Ford results in our West segment which relate to contractual step-downs in minimum volume commitments.

Williams seeks to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of safe, clean, and reliable energy infrastructure assets that continue to serve key growth markets and supply basins in the United States. Williams’ growth capital and investment expenditures in 2026 are expected to range from $7.0 billion to $7.6 billion, excluding acquisitions and certain long-lead time equipment for power innovation projects which are backed by reimbursement from the customer if the equipment order is cancelled. Growth capital spending in 2026 primarily includes the Power Innovation projects, Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting growth in the Haynesville Shale basin, and projects supporting the Northeast G&P business. Williams is investing capital in the Louisiana LNG and Driftwood Pipeline projects, as well as the development of its Wamsutter upstream oil and gas properties. In addition to growth capital and investment expenditures, Williams also remains committed to projects that maintain its assets for safe and reliable operations, as well as projects that reduce emissions, and meet legal, regulatory, and/or contractual commitments.

Potential risks and obstacles that could impact the execution of Williams’ plan include:

•A global recession, which could result in downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;

•Opposition to, and regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;

•Counterparty credit and performance risk;

•Unexpected significant increases in capital expenditures or delays in capital project execution, including increases from inflation or delays caused by supply chain disruptions;

•Unexpected changes in customer drilling and production activities, which could negatively impact gathering and processing volumes;

•Lower than anticipated demand for natural gas and natural gas products which could result in lower-than-expected volumes, energy commodity prices, and margins;

•General economic, financial markets, or industry downturns, including increased inflation, interest rates, or tariffs;

•Physical damages to facilities, including damage to offshore facilities by weather-related events;

•Other risks set forth under Part I, Item 1A. Risk Factors in the Annual Report on Form 10-K for the year ended December 31, 2025, as filed with the SEC on February 24, 2026, as may be supplemented by disclosure in Part II, Item 1A. Risk Factors in subsequent Quarterly Reports on Form 10‑Q.

Expansion Projects

Williams’ ongoing major expansion projects include the following:

Transmission, Power & Gulf

Gillis West

In April 2026, Transco filed a prior notice application with the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Louisiana to delivery points in Texas. Transco plans to place the project into

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service as early as the fourth quarter of 2026, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 115 Mdth/d.

Southeast Supply Enhancement

In January 2026, Transco received FERC approval for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Virginia to delivery points in Virginia, North Carolina, South Carolina, Georgia, and Alabama. Transco plans to place the project into service as early as the third quarter of 2027, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 1,597 Mdth/d.

Northeast Supply Enhancement

In August 2025, the FERC issued an order granting Transco’s petition for reissuance of the certificate authorization for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Transco’s Compressor Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York. In Oct

[Excerpt truncated for page length; source filing is linked above.]

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

Williams is an energy company committed to being the leader in providing infrastructure that safely delivers natural gas products to reliably fuel the clean energy economy. Its operations are located in the United States.

Williams’ interstate natural gas pipeline strategy is to create value by maximizing the utilization of its pipeline capacity by providing high-quality, low-cost transportation of natural gas to large and growing markets. Williams’ gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC. As such, Williams’ rates and charges for the transportation of natural gas in interstate commerce; the extension, expansion, or abandonment of jurisdictional facilities; and accounting, among other things, are subject to regulation. The rates are established primarily through the FERC’s ratemaking process, but Williams may also negotiate rates with its customers pursuant to the terms of its tariffs and FERC policy. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of the cost of service is recovered through firm capacity reservation charges in transportation rates.

The ongoing strategy of Williams’ midstream operations is to safely and reliably operate large-scale midstream infrastructure where its assets can be fully utilized and drive low per-unit costs. Williams focuses on consistently attracting new business by providing highly reliable service to its customers. These services include natural gas gathering and processing, treating, compression and storage; NGL fractionation, transportation and storage; and crude oil production handling and transportation, as well as marketing services for NGL, crude oil, and natural gas.

Consistent with the manner in which Williams’ CODM evaluates performance and allocates resources, Williams’ operations are conducted, managed, and presented within the following reportable segments: Transmission, Power & Gulf; Northeast G&P; West; and Gas & NGL Marketing Services. All remaining business activities, including upstream operations and corporate activities, are included in Other. See Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies for a full description of each segment.

Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity relates to Williams’ current continuing operations and should be read in conjunction with the financial statements and combined notes thereto included in Part II, Item 8. Financial Statements and Supplementary Data of this report.

Dividends

In December 2025, Williams paid a regular quarterly dividend of $0.500 per share. On January 27, 2026, Williams’ board of directors approved a regular quarterly dividend of $0.525 per share payable on March 30, 2026.

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Overview of Year Ended December 31, 2025

Net income (loss) attributable to The Williams Companies, Inc. for the year ended December 31, 2025, increased $393 million compared to the year ended December 31, 2024. Further discussion of the results is found in this report in the Results of Operations.

Recent Developments

Transco FERC Rate Case Filing

On August 30, 2024, Transco filed a general rate case with the FERC for an overall increase in rates and to comply with the terms of the settlement of its prior rate case. On September 30, 2024, the FERC issued an order accepting and suspending Transco’s general rate filing to be effective March 1, 2025, subject to refund and the outcome of hearing procedures established by the FERC. The order also accepted rate decreases for certain services to be effective as of October 1, 2024. During the third quarter of 2025, Transco reached an agreement in principle with its customers and the other participants to settle all aspects of the rate case and has accrued a related liability for rate refunds. Transco filed with the FERC in October 2025 for approval of the settlement. On December 30, 2025, the FERC approved the settlement which will become effective March 1, 2026.

Power Innovation Projects

Williams continues to pursue projects to support the power demands created by new data center and industrial development in power grid-constrained markets, including agreements with a large, investment-grade company to provide onsite natural gas and power generation infrastructure. See Expansion Projects for further discussion.

Sale of Mid-Continent Gathering Assets

In December 2025, Williams’ management approved a plan to sell certain gas gathering assets in the Mid-Continent region. These operations were designated as held for sale at December 31, 2025 and an impairment, within the West segment, has been recognized for 2025.

Sale of South Mansfield Upstream Interests

In October 2025, Williams entered into an agreement to sell its interests in certain upstream ventures in the South Mansfield area of the Haynesville Shale region, included in Other, for consideration of $398 million with additional contingent consideration to possibly be received through 2029. The transaction closed in January 2026, and Williams expects to recognize a gain in the first quarter of 2026.

Investments in Louisiana LNG and Driftwood Pipeline Projects

In October 2025, Williams closed on various agreements with the same counterparty to acquire a 10 percent equity-method investment in Louisiana LNG, which is developing a fully permitted LNG export facility, and an 80 percent interest in Driftwood Pipeline, which is constructing a fully permitted greenfield pipeline, Line 200, connecting to multiple other pipelines, including Transco and Louisiana Energy Gateway, to supply the LNG facility. Williams will be the operator of the pipeline. The total initial purchase price was $378 million, and both investments will require additional capital to fund further construction. Williams will also manage the gas supply for the LNG facility and purchase approximately 10 percent of the LNG produced.

Saber Asset Purchase

In June 2025, Williams acquired 100 percent of Saber Midstream, LLC (Saber). The acquisition, which was accounted for as an asset purchase, included cash consideration of $47 million and the retention of $113 million of Saber’s debt, which was separately repaid in full within the same month. Saber operates a gas gathering system in the Haynesville Shale region in the West segment.

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Cogentrix Investment

In March 2025, Williams purchased a minority interest in Cogentrix for $153 million, which is accounted for as an equity-method investment within the Gas & NGL Marketing Services segment. Cogentrix owns interests in 11 natural gas power plants (see Note 8 – Investing Activities).

Rimrock Asset Purchase

On January 31, 2025, Williams purchased a group of natural gas gathering and processing assets from Rimrock Energy Partners, LLC (Rimrock) for approximately $325 million, to expand Williams’ gathering and processing footprint and create operational synergies in the DJ Basin in the West segment.

Expansion Project Updates

Expansion projects placed into service for the current year are described below. Ongoing major expansion projects are discussed later in Company Outlook.

Transmission, Power & Gulf

Overthrust Westbound Compression Expansion

In October 2024, MountainWest received approval from the FERC for the project, which involves an expansion of MountainWest’s existing natural gas transmission system to provide incremental firm transportation capacity from multiple receipt points in Wamsutter, Wyoming to a delivery point in Opal, Wyoming. MountainWest placed the project into service in November 2025, increasing capacity by 325 Mdth/d.

Stanfield South

The project on NWP’s existing natural gas transmission system provides year-round transportation capacity from the Stanfield receipt point in Oregon to multiple delivery points in Idaho and a new delivery meter in Wyoming. NWP placed the project into service in November 2025, increasing NWP’s contracted capacity by 80 Mdth/d.

Commonwealth Energy Connector

In November 2023, Transco received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity in Virginia. Transco placed the project into service in November 2025, increasing Transco’s capacity by 105 Mdth/d.

Alabama Georgia Connector

In March 2024, Transco received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Transco’s Station 85 pooling point in Alabama to customers in Georgia. Transco placed the project into service in October 2025, increasing Transco’s capacity by 64 Mdth/d.

Deepwater Shenandoah Project

In June 2021, Williams reached an agreement with two third parties to provide offshore natural gas gathering and transportation services as well as onshore natural gas processing services. The project expands the existing Gulf of America offshore infrastructure connecting to a third-party offshore lateral pipeline from the Shenandoah platform to Discovery’s existing Keathley Canyon Connector pipeline, adds onshore processing

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facilities at Larose, Louisiana to handle the expected rich Shenandoah production, and the natural gas liquids are now fractionated and marketed at Discovery’s Paradis plant in Louisiana. This project was placed into service in July 2025.

Texas to Louisiana Energy Pathway

In January 2024, Transco received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide firm transportation capacity from receipt points in south Texas to delivery points in Texas and Louisiana. Transco placed the project into service in April 2025. Under the project, Transco provides 364 Mdth/d of new firm transportation service through a combination of increasing capacity, converting interruptible capacity to firm, and utilizing existing capacity.

Southeast Energy Connector

In November 2023, Transco received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Mississippi and Alabama to a delivery point in Alabama. Transco placed the project into service in April 2025, increasing Transco’s capacity by 150 Mdth/d.

Deepwater Whale Project

In August 2021, Williams reached an agreement with two third parties to provide offshore natural gas gathering and crude oil transportation services as well as onshore natural gas processing services. The project expands its existing Western Gulf of America offshore infrastructure via a 26-mile gas lateral pipeline from the Whale platform to the existing Perdido gas pipeline and adds a new 124-mile oil pipeline from the Whale platform to Williams’ existing junction platform. This project was placed into service in January 2025.

West

Haynesville Gathering Expansion

In February 2023, Williams announced its agreement with a third party to facilitate natural gas production growth in the Haynesville Shale basin for the construction of a greenfield gathering system in support of a 26,000-acre dedication. In April 2025, the third party sold a majority of their ownership interest to another party, with both third parties agreeing to long-term capacity commitments on Williams’ Louisiana Energy Gateway expansion project. This project was placed into service in September 2025, providing natural gas gathering services to both parties.

Louisiana Energy Gateway

In August 2024, Williams began construction activities on new natural gas gathering assets in the Haynesville Shale basin to increase delivery of natural gas to premium markets, including Transco, industrial markets, and growing LNG export demand along the Gulf Coast. This project was placed into service in July and August 2025, increasing natural gas gathering capacity by 1.8 Bcf/d.

Company Outlook

Williams’ strategy is to provide a large-scale, reliable, and clean energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. Williams accomplishes this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. Williams continues to maintain a strong commitment to safety, environmental stewardship including seeking opportunities for renewable energy ventures, operational excellence, and customer satisfaction. Williams believes that accomplishing these goals will position it

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to deliver safe, reliable, clean energy services to its customers and an attractive return to shareholders. Williams’ business plan for 2026 includes a continued focus on earnings and cash flow growth.

In 2026, Williams’ operating results are expected to benefit from the continued growth in the Transmission, Power & Gulf segment, primarily reflecting the impacts of the Socrates Power Innovation project, as well as numerous expansion projects at Transco and the Gulf of America. Growth in 2026 will benefit from a full year of the Louisiana Energy Gateway expansion project as well as expected increases in Haynesville Shale volumes. Additionally, Williams expects higher gathering and processing results in the Northeast. These increases are partially offset by the divestiture of the South Mansfield upstream joint venture, and lower expected Eagle Ford results in our West segment related to minimum volume commitment reductions.

Williams seeks to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of safe, clean, and reliable energy infrastructure assets that continue to serve key growth markets and supply basins in the United States. Williams’ growth capital and investment expenditures in 2026 are expected to range from $6.1 billion to $6.7 billion, excluding acquisitions and certain long-lead time equipment for power innovation projects which are backed by reimbursement from the customer if the equipment order is cancelled. Growth capital spending in 2026 primarily includes the Power Innovation projects, Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting growth in the Haynesville Shale basin, and projects supporting the Northeast G&P business. Williams is investing capital in the Louisiana LNG and Driftwood Pipeline projects, as well as the development of its Wamsutter upstream oil and gas properties. In addition to growth capital and investment expenditures, Williams also remains committed to projects that maintain its assets for safe and reliable operations, as well as projects that reduce emissions, and meet legal, regulatory, and/or contractual commitments. See Note 18 – Contingencies and Commitments for further discussion of Williams’ commitments.

Potential risks and obstacles that could impact the execution of Williams’ plan include:

•A global recession, which could result in downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;

•Opposition to, and regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;

•Counterparty credit and performance risk;

•Unexpected significant increases in capital expenditures or delays in capital project execution, including increases from inflation or delays caused by supply chain disruptions;

•Unexpected changes in customer drilling and production activities, which could negatively impact gathering and processing volumes;

•Lower than anticipated demand for natural gas and natural gas products which could result in lower-than-expected volumes, energy commodity prices, and margins;

•General economic, financial markets, or industry downturns, including increased inflation, interest rates, or tariffs;

•Physical damages to facilities, including damage to offshore facilities by weather-related events;

•Other risks set forth under Part I, Item 1A. Risk Factors.

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Expansion Projects

Williams’ ongoing major expansion projects include the following:

Transmission, Power & Gulf

Gillis West

Transco plans to file a prior notice application with the FERC in 2026 for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Louisiana to delivery points in Texas. Transco plans to place the project into service as early as the second quarter of 2026, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 115 Mdth/d.

Southeast Supply Enhancement

In January 2026, Transco received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Virginia to delivery points in Virginia, North Carolina, South Carolina, Georgia, and Alabama. Transco plans to place the project into service as early as the third quarter of 2027, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 1,597 Mdth/d.

Northeast Supply Enhancement

In August 2025, the FERC issued an order granting Transco’s petition for reissuance of the certificate authorization for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Transco’s Compressor Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York. In October and November 2025, Transco’s applications for Clean Water Act and related permits with the states of Pennsylvania, New York and New Jersey were approved. In August 2025, Transco executed precedent agreements with customers subscribing to all of the capacity under the project. Transco plans to place the project into service as early as the fourth quarter of 2027, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 400 Mdth⁄d.

Pine Prairie Phase IV Expansion

In August 2025, Williams filed a certificate application with the FERC for the project, which will involve an expansion of storage capacity and the injection and withdrawal capabilities of one of its existing storage facilities in the Gulf Coast region. Williams plans to place the project into service during the fourth quarter of 2028, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase working gas storage capacity by 10 Bcf.

Dalton Lateral II

Transco plans to file a certificate application for the project with the FERC in 2027. The project involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Transco’s main line near existing Station 115 to an existing power plant in Georgia. Transco plans to place the project into service as early as the fourth quarter of 2029, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity up to 460 Mdth/d.

Power Express

Transco plans to file an application with the FERC as early as the second quarter 2027 for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm

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transportation capacity in Virginia. Transco plans to place the project into service as early as the third quarter of 2030, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 689 Mdth/d.

Naughton Coal-to-Gas Conversion

The project involves an expansion of NWP’s existing natural gas transmission system to provide year-round transportation capacity to a power plant in southwest Wyoming. NWP plans to place the project into service as early as the second quarter of 2026, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 98 Mdth/d.

Ryckman Creek Loop

In January 2026, NWP received approval from the FERC for the project, which involves an expansion of NWP’s existing natural gas transmission system to provide incremental firm transportation capacity from a receipt point in northeast Oregon to multiple delivery points in southwest Wyoming. NWP plans to place the project into service as early as the fourth quarter of 2026. The project is expected to increase capacity by 50 Mdth/d.

Huntingdon Connector

NWP plans to file a prior notice application for the project with the FERC in the first quarter of 2026. The project involves an expansion of NWP’s existing natural gas transmission system that will provide year-round transportation capacity from the Sumas receipt point to various delivery points in Washington. NWP plans to place the project into service during the fourth quarter of 2026, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 78 Mdth/d.

Wild Trail

In May 2025, NWP filed a certificate application with the FERC for the project, which involves an expansion of NWP’s existing natural gas transmission system that will provide year-round transportation capacity from the White River Hub receipt point in western Colorado to various delivery points in southwest Wyoming and southern Colorado. The Wild Trail project is fully subscribed by an affiliate of NWP. NWP plans to place the project into service during the fourth quarter of 2027, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 83 Mdth/d.

Kelso-Beaver Reliability

In November 2025, NWP received approval from the FERC for the project. The Kelso-Beaver Reliability project on NWP’s existing natural gas transmission system will provide year-round transportation capacity to various receipt and delivery points in Oregon. NWP plans to place the project into service during the fourth quarter of 2028, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 183 Mdth/d.

Power Innovation

Socrates

Williams has received approval from the Ohio Power Siting Board for the power generation facilities and is expecting final approval for the associated gas pipeline infrastructure in the first half of 2026. The Socrates project involves the construction of the Socrates North and South power generation facilities in New Albany, Ohio. Williams has agreed to provide committed power generation and associated gas pipeline infrastructure for the project, which is expected to provide a combined 400 megawatts of onsite power generation capacity to the customer. The project is backed by a 10 year, primarily fixed-price power

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purchase agreement, with an option for the customer to extend the term of the agreement. Williams plans to place the project into service in the third and fourth quarter of 2026, assuming timely receipt of permits.

Additional Projects

Williams has agreed to provide committed power generation and associated gas pipeline infrastructure for three additional Power Innovation projects, Apollo, Aquila and Socrates the Younger. The projects are backed by primarily fixed-price power purchase agreements, with options for the customer to extend the term of the agreements. The Apollo project, in Ohio, has a term of 12.5 years, and Williams expects the project to be placed into service in the second half of 2027. The Aquila project, in Utah, also has a term of 12.5 years, and Williams expects the project to be placed into service in the second half of 2027 and the first half of 2028. The Socrates the Younger project, in Ohio, has a term of 10 years, and Williams expects the project to be placed into service the second half of 2028. All expected in-service dates assume timely receipt of permits.

West

Dorne

Williams will construct and operate a greenfield treating and dehydration facility with a capacity of 400 MMcf/d. This project is expected to be placed into service in the third quarter of 2027.

Critical Accounting Estimates

Preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. The nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on the financial condition or results of operations.

Regulatory Accounting

Williams’ regulated interstate natural gas pipelines, including Transco and NWP, are regulated by the FERC. Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” (ASC 980) provides that certain costs that would otherwise be charged to expense should be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense should be deferred as regulatory liabilities, based on the expected return to customers in future rates. Management’s expected recovery of deferred costs and return of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. Certain incurred costs and obligations are recorded as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refunded in future rates.

Accounting for operations that are regulated and apply the provisions of ASC 980 can differ from the accounting requirements for nonregulated operations. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, levelized cost of service, employee-related benefits, environmental costs, negative salvage, asset retirement obligations (AROs), as well as other costs and taxes included in, or expected to be included in, future rates. Management has determined that for its rate-regulated entities, it is appropriate to apply the accounting prescribed by ASC 980 and, accordingly, the accompanying financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. Management’s assessment of the probability of recovery or pass-through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, any of Williams’ regulated interstate natural gas pipelines, including Transco or NWP, ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the respective

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balance sheet and included in the respective statement of income for the period in which the discontinuance of regulatory accounting treatment occurs and can be estimated, unless otherwise required to be recorded under other provisions of U.S. generally accepted accounting principles.

The aggregate amount of regulatory assets reflected on Williams’ Consolidated Balance Sheet was $698 million at December 31, 2025, of which Transco’s and NWP’s Balance Sheets reflected $394 million and $83 million, respectively. The aggregate amount of regulatory liabilities reflected on Williams’ Consolidated Balance Sheet was $1.3 billion at December 31, 2025, of which Transco’s and NWP’s Balance Sheets reflected $1.0 billion and $245 million, respectively. A summary of regulatory assets and liabilities is included in Note 10 – Regulatory Assets and Liabilities.

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Results of Operations

Williams’ Consolidated Overview

The following table and discussion is a summary of Williams’ consolidated results of operations for the three years ended December 31, 2025, and should be read in conjunction with the results of operations by segment, as discussed in further detail following this consolidated overview discussion.

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*    + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.

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Management’s Discussion and Analysis (Continued)

2025 vs. 2024

Service revenues increased primarily due to:

•Higher revenues associated with expansion projects at the Transmission, Power & Gulf and the West segments;

•Increased Transco transportation and storage rates and Gulf Coast Storage rates at the Transmission, Power & Gulf segment;

•Higher volumes from the August 2024 Discovery Acquisition at the Transmission, Power & Gulf segment, the June 2025 Saber Asset Purchase and the January 2025 Rimrock Asset Purchase at the West segment, and higher volumes from the Northeast JV at the Northeast G&P segment;

•Higher revenues associated with reimbursable expenses primarily in the Northeast G&P segment, which is offset by similar changes in the charges reflected in Operating and maintenance expenses; partially offset by

•Lower revenues in the Eagle Ford Shale region due to lower MVC revenue at the West segment.

The net sum of Product sales and service revenues – commodity consideration, Product costs and net processing commodity expenses, and net realized gains and losses on commodity derivatives related to sales of product and shrink gas purchases for processing plants for the reportable segments comprise Commodity Margins. Service revenues - commodity consideration represent payments received in the form of commodities for processing services provided. Most of these commodity volumes are sold during the month processed and are offset within Product costs and net processing commodity expenses. The sum of Product sales and net realized gains and losses on commodity derivatives related to the upstream operations comprise Net realized product sales.

The Product sales and service revenues – commodity consideration increase primarily consists of:

•Higher product sales from upstream operations primarily related to higher volumes, including the November 2024 Crowheart Acquisition (See Note 3 – Acquisitions and Divestitures), and natural gas prices at Other;

•Higher equity NGL sales and commodity consideration revenues associated with equity NGL production activity primarily due to the Discovery Acquisition at the Transmission, Power & Gulf segment;

•Higher marketing sales activities primarily related to higher net gas marketing sales activities, partially offset by lower NGL marketing sales activities at the Gas & NGL Marketing Services segment;

•Higher cash-out activity primarily at the Transmission, Power & Gulf segment.

As Williams is acting as agent for natural gas marketing customers, its natural gas marketing product sales are presented net of the related costs of those activities within the Gas & NGL Marketing Services segment.

Net gain (loss) from commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues primarily in the Gas & NGL Marketing Services segment, as well as upstream operations at Other (see Note 17 – Commodity Derivatives).

Williams experiences significant earnings volatility from the fair value accounting required for the derivatives used to hedge a portion of the economic value of the underlying transportation and storage capacity portfolios as well as upstream-related production. However, the unrealized fair value measurement gains and losses on the derivatives are generally offset by valuation changes in the economic value of the underlying production or transportation and storage capacity contracts, which are not recognized until the underlying transaction occurs.

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Management’s Discussion and Analysis (Continued)

The Product costs and net processing commodity expenses increase primarily consists of:

•Higher shrink natural gas purchases and commodity consideration costs associated with Williams’ equity NGL production activities primarily due to the Discovery Acquisition at the Transmission, Power & Gulf segment;

•Higher cash-out activity primarily at the Transmission, Power & Gulf segment; partially offset by

•Lower marketing activities primarily related to NGL’s at the Gas & NGL Marketing Services segment.

Operating and maintenance expenses increased primarily due to operating costs of the assets acquired at the Transmission, Power & Gulf and West segments, as well as upstream operations at Other, and higher electricity and fuel primarily in the Northeast G&P segment (substantially offset by higher Service revenues discussed above), partially offset by the absence of the impact of a 2024 change in practice related to payroll timing.

Depreciation, depletion, and amortization expenses increased primarily related to assets acquired and expansion projects placed in-service at the Transmission, Power & Gulf and West segments, as well as upstream operations at Other and an increase in Transco depreciation rates associated with the rate case at the Transmission, Power & Gulf segment, partially offset by lower ARO-related depreciation at the Transmission, Power & Gulf segment.

General and administrative expenses increased due to higher employee-related costs, partially offset by lower acquisition and transition costs primarily at the Transmission, Power & Gulf segment and the absence of the impact of a 2024 change in a practice related to payroll timing.

Impairment or write-off of certain assets includes an impairment to certain assets held for sale in the Mid-Continent region and the write-off of certain DJ Basin region assets in the West segment in 2025.

The unfavorable change in Other (income) expense – net within Operating income (loss) includes net unfavorable changes to charges and credits associated with amortization of regulatory assets and liabilities related to the Transco rate case and deferral of ARO-related depreciation at the Transmission, Power & Gulf segment.

Equity earnings (losses) changed favorably primarily due to the impact of $153 million from our investment Cogentrix in 2025 (see Note 8 – Investing Activities) and increases at Blue Racer and Appalachia Midstream Investments.

The unfavorable change in Other investing income (loss) – net includes the absence of a $149 million gain on the sale of our interests in Aux Sable in 2024 (see Note 8 – Investing Activities), a $127 million gain on remeasurement of our existing equity-method investment associated with the purchase of the remaining interest in Discovery in 2024, and lower interest income earned on lower cash and cash equivalent balances.

Interest expense was primarily impacted by 2024 and 2025 debt issuances, partially offset by 2024 and 2025 debt retirements and the absence of imputed interest on deferred consideration obligations related to previous acquisitions (see Note 13 – Debt and Banking Arrangements).

The unfavorable change in Other income (expense) – net below Operating income (loss) includes a decrease in equity AFUDC primarily as a result of the timing of capital projects within the regulated businesses.

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income and the absence of a benefit associated with a decrease in the estimate of the state deferred income tax rate in 2024. See Note 6 – Provision (Benefit) for Income Taxes for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

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Management’s Discussion and Analysis (Continued)

2024 vs. 2023

Service revenues increased primarily due to:

•Higher volumes from the November 2023 DJ Basin Acquisitions at the West segment and the January 2024 Gulf Coast Storage, August 2024 Discovery, and February 2023 MountainWest Acquisitions at the Transmission, Power & Gulf segment; partially offset by lower volumes from the September 2023 sale of certain liquids pipelines at the Transmission, Power & Gulf segment (see Note 3 – Acquisitions and Divestitures),

•Higher revenues associated with expansion projects at the Transmission, Power & Gulf segment, partially offset by

•Lower gathering volumes at the West and Northeast G&P segments.

The Product sales and service revenues – commodity consideration increase primarily consists of:

•Higher marketing sales activities primarily at the West segment primarily related to the DJ Basin Acquisitions and Transmission, Power & Gulf segment primarily related to the Discovery Acquisition; partially offset by lower marketing sales activities related to NGLs at the Gas & NGL Marketing Services segment, primarily related to activity associated with the sale certain liquids pipelines. Net natural gas marketing sales were impacted by higher storage costs; partially offset by

•Lower system management gas sales primarily at the Transmission, Power & Gulf segment;

•Lower product sales from upstream operations; partially offset by higher volumes from the November 2024 Crowheart Acquisition at Other;

•Lower equity NGL sales and commodity consideration revenues associated with NGL production activity primarily at the West segment; partially offset by higher activity in the Transmission, Power & Gulf segment primarily due to the Discovery Acquisition.

Net gain (loss) from commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues primarily in the Gas & NGL Marketing Services and West segments, and upstream operations at Other.

The Product costs and net processing commodity expenses increase primarily consists of:

•Higher marketing activities primarily at the West segment primarily related to the DJ Basin Acquisitions and Transmission, Power & Gulf segment primarily related to the Discovery Acquisition; partially offset by lower marketing activities primarily related to NGLs at the Gas & NGL Marketing Services segment; partially offset by

•Lower shrink natural gas purchases and commodity consideration costs associated with Williams’ equity NGL production activities primarily at the West segment.

Operating and maintenance expenses increased primarily due to operating costs of the assets acquired at the West and Transmission, Power & Gulf segments; as well as unfavorable changes in employee-related costs, including the impact of a change in a practice related to payroll timing; and the net imbalance liability due to changes in pricing.

Depreciation, depletion, and amortization expenses increased primarily related to the assets acquired at the Transmission, Power & Gulf and West segments and an increase at Transco related to additional assets placed in service. The increase is partially offset by lower amortization of intangibles related to the acquisition of Sequent Energy Management, L.P. and Sequent Energy Canada, Corp. (Sequent) in 2021.

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Management’s Discussion and Analysis (Continued)

General and administrative expenses increased primarily due to employee-related costs, including the impact of a change in a practice related to payroll timing, partially offset by lower acquisition and transition-related costs associated with the MountainWest Acquisition (see Note 3 – Acquisitions and Divestitures).

Gain on sale of business reflects a gain from the sale of certain liquids pipelines in the Transmission, Power & Gulf segment in 2023.

Other (income) expense – net within Operating income (loss) includes lower project feasibility costs at our Transmission, Power & Gulf segment; partially offset by the absence of a 2023 gain related to a contract settlement.

Equity earnings (losses) changed unfavorably primarily due to the impacts of the consolidation of RMM and Discovery, and the sale of the interests in Aux Sable (see Note 8 – Investing Activities), partially offset by the absence of the share of a loss contingency accrual in 2023 at Aux Sable and favorable results at OPPL.

Other investing income (loss) – net includes gains on the sale of the interests in Aux Sable and the gain on remeasuring the existing equity-method investment in Discovery to fair value with the acquisition of the remaining 40 percent ownership, partially offset by the absence the 2023 gain on remeasuring the existing equity-method investment in RMM to fair value with the acquisition of the remaining 50 percent ownership (see Note 8 – Investing Activities).

The increase in Interest expense was primarily due to Williams’ 2023 and 2024 debt issuances, and imputed interest on deferred consideration obligations related to the DJ Basin and Gulf Coast Storage Acquisitions, partially offset by 2023 and 2024 debt retirements.

Net gain from Energy Transfer litigation judgment resulted from a favorable ruling on the final order and judgment of Williams’ complaint against Energy Transfer in 2023 (see Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).

Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income and a higher benefit associated with decreases in the estimate of the state deferred income tax rate in both periods.

Income (loss) from discontinued operations in 2023 includes a pre-tax charge of $125 million to increase the accrued liability associated with the Alaska refinery contamination litigation, partially offset by the related income tax effect (see Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).

Period-Over-Period Operating Results – Williams’ Segments

Williams’ CODM evaluates segment operating performance based upon Modified EBITDA. Note 19 – Segment Disclosures includes a reconciliation of this non-GAAP measure to Income (loss) before income taxes. Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of Williams’ assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.

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Management’s Discussion and Analysis (Continued)

Transmission, Power & Gulf

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(1)Included as a component of Commodity margins.

2025 vs. 2024

Transmission, Power & Gulf Modified EBITDA increased primarily due to higher Service revenues, partially offset by higher Other segment costs and expenses.

Service revenues increased primarily due to:

•A $291 million increase in Transco’s revenues primarily associated with expansion projects placed in service, notably Regional Energy Access in August 2024, Southside Reliability Enhancement in November 2024, Texas Louisiana Energy Pathway in April 2025, and Southeast Energy Connector in April 2025; and transportation and storage rate increases;

•A $96 million increase in the Western Gulf Coast region primarily due to higher natural gas gathering and crude oil transportation volumes from the Whale expansion project that went in-service in January 2025;

•A $78 million increase primarily in natural gas gathering revenues due to the Discovery Acquisition and volumes from the Shenandoah expansion project that went in-service in July 2025 (see Note 3 – Acquisitions and Divestitures);

•A $49 million increase in the Eastern Gulf Coast region primarily due to higher production handling, crude oil transportation and natural gas gathering volumes from new wells at Gulfstar One in the Pickerel field and at Blind Faith in the Ballymore field and the absence of shut-ins due to weather-related events, partially offset by shut-ins for maintenance activities at Devils Tower impacting the Taggart and Kodiak fields;

•A $45 million increase in Gulf Coast Storage’s revenues primarily associated with higher storage rates;

•A $14 million increase in NWP’s revenues primarily due to transportation rate increases.

Commodity margins increased primarily due to the Discovery Acquisition.

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Management’s Discussion and Analysis (Continued)

Other segment costs and expenses increased primarily due to:

•Unfavorable change in equity AFUDC primarily as a result of the timing of capital projects within the regulated businesses;

•Net unfavorable changes in charges and credits associated with regulatory assets and liabilities related to the rate case at Transco;

•Higher operating expenses and administrative costs including increased operating costs resulting from the Discovery Acquisition, corporate allocations, and property taxes, as well as higher employee-related costs, partially offset by the absence of acquisition and transition costs related to the Gulf Coast Storage Acquisition in January 2024 (see Note 3 – Acquisitions and Divestitures) and a 2024 change in a practice related to payroll timing;

•Unfavorable change in the deferral of ARO-related depreciation at Transco; partially offset by

•A net favorable change related to certain asset retirements in the Western Gulf Coast region in 2025.

Proportional Modified EBITDA of equity-method investments decreased primarily due to lower proportional results as Discovery was consolidated following its August 2024 acquisition.

2024 vs. 2023

Transmission, Power & Gulf Modified EBITDA increased primarily due to higher Service revenues, partially offset by the absence of a Gain on sale of business, higher Other segment costs and expenses, and lower Proportional Modified EBITDA of equity-method investments.

Service revenues increased primarily due to:

•A $220 million increase primarily in storage revenues due to the Gulf Coast Storage Acquisition in January 2024 (see Note 3 – Acquisitions and Divestitures);

•A $121 million increase in Transco’s revenues primarily associated with expansion projects and higher park and loan services;

•A $41 million increase primarily in gathering revenues due to the Discovery Acquisition in August 2024;

•A $38 million increase in primarily transportation and storage revenues due to the MountainWest Acquisition in February 2023 (see Note 3 – Acquisitions and Divestitures);

•A $22 million increase in NorTex’s revenues primarily associated with higher storage rates; partially offset by

•A $39 million decrease primarily in transportation revenues due to the sale of certain liquids pipelines in the Gulf Coast region in September 2023 (see Note 3 – Acquisitions and Divestitures);

•A $34 million decrease in the Eastern Gulf region primarily due to shut-ins for producer operational issues at Gulfstar One in the Gunflint and Tubular Bells fields and weather-related events, partially offset by higher primarily production handling volumes from a new well at Gulfstar One in the Pickerel field.

Other segment costs and expenses increased primarily due to:

•Higher operating expenses and administrative costs including higher operating, acquisition and transition costs related to Williams’ Gulf Coast Storage and Discovery Acquisitions, and employee-related costs, including the impact of a change in a practice related to payroll timing; partially offset by significantly

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lower acquisition and transition costs related to Williams’ MountainWest Acquisition, contract services at Transco, and operating costs related to the sale of certain liquids pipelines in the Gulf Coast region;

•Unfavorable change in the amortization of regulatory pension liabilities at Transco; partially offset by

•Lower project feasibility costs;

•A favorable change in equity AFUDC primarily as a result of increased capital expenditures at Williams’ regulated businesses.

Commodity margins increased primarily due to a $19 million increase from Williams’ equity NGLs primarily due to the Discovery Acquisition.

Gain on sale of business reflects a gain recognized on the sale of certain liquids pipelines in the Gulf Coast region in September 2023.

Proportional Modified EBITDA of equity-method investments decreased primarily due to lower proportional results as Discovery was consolidated.

Northeast G&P

(1)Included as a component of Commodity margins.

2025 vs. 2024

Northeast G&P Modified EBITDA increased primarily due to higher Service revenues and higher Proportional Modified EBITDA of equity-method investments, partially offset by higher Other segment costs and expenses.

Service revenues increased primarily due to:

•A $40 million increase in revenues at the Northeast JV primarily related to higher transportation & fractionation volumes, higher gathering volumes, and higher processing rates;

•A $29 million increase in revenues associated with reimbursable expenses, which is offset by similar changes in the charges reflected in Other segment costs and expenses;

•An $11 million increase in gathering revenues in the Utica Shale region primarily related to higher volumes at Cardinal; partially offset by

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•A $6 million decrease in gathering revenues at Susquehanna Supply Hub primarily related to lower volumes partially offset by escalated rates.

Other segment costs and expenses increased primarily due to higher operating expenses, including higher electricity and fuel (substantially offset by higher Service revenues discussed above) and higher maintenance expenses. The increase was partially offset by lower employee-related costs related to the absence of the impact of a 2024 change in a practice related to payroll timing.

Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments primarily driven by escalated gathering rates and higher gathering volumes, at Blue Racer primarily due to higher volumes and annual rate escalations, and at Laurel Mountain primarily due to higher commodity-based gathering rates and higher volumes. The increase was partially offset by a decrease at Aux Sable Liquid Products LP due to the sale of Williams’ investment in the third quarter of 2024.

2024 vs. 2023

Northeast G&P Modified EBITDA increased primarily due to higher Proportional Modified EBITDA of equity-method investments, higher Service revenues, and higher Commodity margins, partially offset by higher Other segment costs and expenses.

Service revenues increased primarily due to:

•A $20 million increase in revenues at the Northeast JV primarily related to higher gathering volumes as well as higher transportation & fractionation, gathering, and processing rates, partially offset by lower transportation & fractionation and processing volumes;

•A $16 million increase in joint venture operating fees primarily related to assuming operatorship of Blue Racer effective January 1, 2024, (which is significantly offset by higher Other segment costs and expenses discussed below);

•An $11 million increase in revenues associated with reimbursable expenses, which is offset by similar changes in the charges reflected in Other segment costs and expenses; partially offset by

•A $19 million decrease in gathering revenues at Susquehanna Supply Hub primarily related to lower volumes partially offset by escalated rates;

•A $16 million decrease in gathering revenues in the Utica Shale region primarily related to lower volumes at Flint and Cardinal partially offset by escalated rates.

Commodity margins increased due to a restructured gas purchase deal in 2024 which allowed for margin gain on residue pricing and liquids from fixed recoveries. In addition, Williams was not significantly impacted by system constraints which impacted margins in 2023.

Other segment costs and expenses increased primarily due to higher employee-related costs, including the impact of a change in a practice related to payroll timing, as well as higher operating expenses, including higher electricity and fuel, and increased support costs related to assuming operatorship of Blue Racer effective January 1, 2024 (substantially offset by higher Service revenues discussed above). The increase was partially offset by lower maintenance expenses and the absence of the 2023 loss contingency accrual.

Proportional Modified EBITDA of equity-method investments increased at Aux Sable Liquid Products LP primarily due to the absence of Williams’ $31 million share of a loss contingency accrual related to its former ownership in 2023, as well as the terms of the new product marketing agreement, partially offset by the sale of Williams’ investment in Aux Sable Liquid Products LP in the third quarter of 2024. Additionally, Appalachia

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Midstream Investments increased primarily driven by higher gathering rates partially offset by lower volumes and higher expenses.

West

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(1)    Included as a component of Commodity margins.

2025 vs. 2024

West Modified EBITDA decreased primarily due to the 2025 Impairment or write-off of certain assets, partially offset by higher Service revenues.

Service revenues increased primarily due to:

•A $121 million increase in the Haynesville Shale region primarily due to higher gathering volumes including those resulting from Louisiana Energy Gateway which was placed into service in third-quarter 2025 and the Saber Asset Purchase;

•A $60 million increase in the DJ Basin region primarily due to higher gathering volumes associated with the Rimrock Asset Purchase;

•A $17 million increase in the Barnett Shale region primarily due to higher gathering rates driven by favorable commodity pricing; partially offset by

•A $77 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenue.

Commodity margins increased $21 million primarily due to $12 million higher margins from equity NGLs associated with higher net realized NGL sales prices as well as higher volumes of equity NGL sold, and a $12 million increase in marketing margins primarily associated with the DJ Basin Acquisitions, as previously discussed.

Other segment costs and expenses increased primarily due to higher operating expenses associated with the Rimrock Asset Purchase.

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Impairment or write-off of certain assets reflects the $176 million impairment of Mid-Continent assets held for sale, and $36 million write-off of certain compression and processing assets in the DJ Basin region.

Proportional Modified EBITDA of equity-method investments increased primarily due to higher rates and volumes at OPPL.

2024 vs. 2023

West Modified EBITDA increased primarily due higher Service revenues and Commodity margins, partially offset by higher Other segment costs and expenses, an unfavorable change in Net realized gain (loss) from commodity derivatives relating to service revenues, and lower Proportional Modified EBITDA of equity-method investments.

Service revenues increased primarily due to:

•A $249 million increase in the DJ Basin region associated with the DJ Basin Acquisitions in November 2023 (see Note 3 – Acquisitions and Divestitures);

•A $35 million increase in other NGL operations associated with higher fractionation and transportation revenue due to higher volumes and higher storage fees primarily due to a new contract;

•A $14 million increase in the Wamsutter region primarily associated with higher gathering volumes from increased producer activity as well as higher volumes associated with the absence of weather-related events in first-quarter 2023;

•A $12 million increase associated with reimbursable compressor power and fuel purchases primarily due to the DJ Basin Acquisitions as previously discussed, which are offset by similar changes in Other segment costs and expenses; partially offset by

•A $45 million decrease in the Haynesville Shale region primarily due to lower gathering volumes from decreased producer activity, partially offset by higher gathering rates;

•A $31 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenues;

•A $24 million decrease in the Barnett Shale region primarily due to lower gathering rates driven by unfavorable commodity pricing and lower gathering volumes.

Net realized gain (loss) from commodity derivatives relating to service revenues reflects an unfavorable change in settled commodity prices relative to Williams’ natural gas hedge positions.

Commodity margins increased $63 million primarily due to $39 million higher margins associated with the DJ Basin Acquisitions, as previously discussed. Margins also increased $21 million from Williams’ equity NGLs primarily due to lower net realized prices for natural gas purchases and lower volumes of natural gas purchased both associated with equity NGL production activities; partially offset by lower volumes of equity NGL sold and lower net realized NGL sales prices.

Other segment costs and expenses increased primarily due to higher operating and employee-related expenses including those resulting from the DJ Basin Acquisitions, as previously discussed, the absence of favorable contract settlements in first-quarter 2023, an unfavorable change in Williams’ net imbalance liability due to changes in pricing, higher reimbursable compressor power and fuel purchases which are offset in Service revenues, and the impact of a change in a practice related to payroll timing; partially offset by higher system gains and the absence of a fourth quarter 2023 write-down of assets held for sale.

Proportional Modified EBITDA of equity-method investments decreased primarily due to lower proportional results as RMM was consolidated related to the DJ Basin Acquisitions, as previously discussed, partially offset by higher volumes and higher commodity prices at OPPL.

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Gas & NGL Marketing Services

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(1)    Included as a component of Commodity margins.

2025 vs. 2024

Gas & NGL Marketing Services Modified EBITDA increased primarily due to a favorable change in Net unrealized gain (loss) from commodity derivative instruments and higher Proportional Modified EBITDA of equity-method investments, partially offset by lower Commodity margins.

Commodity margins decreased $99 million primarily due to:

•An $83 million decrease in natural gas marketing margins, including $105 million of lower natural gas transportation capacity marketing margins due to unfavorable net realized pricing spreads. The decrease in natural gas marketing margins was partially offset by $22 million of higher natural gas storage marketing margins primarily driven by higher withdrawals in 2025 compared to 2024, partially offset by less favorable realized derivative gains;

•A $16 million decrease in NGL marketing margins including an unfavorable change in net realized gains and losses on sale of inventory in 2025 compared to 2024 driven by an unfavorable change in NGL prices.

Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and Net processing commodity expenses relates to derivative contracts that are not designated as hedges for accounting purposes. The change from 2024 is primarily due to a change in forward commodity prices relative to hedge positions in 2025 compared to 2024.

Other segment costs and expenses decreased primarily due to lower employee-related costs.

Proportional Modified EBITDA of equity-method investments increased due to the March 2025 investment in Cogentrix.

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2024 vs. 2023

Gas & NGL Marketing Services Modified EBITDA decreased primarily due to an unfavorable change in Net unrealized gain (loss) from commodity derivative instruments and lower Commodity margins.

Commodity margins decreased $64 million primarily due to:

•A $44 million decrease in natural gas marketing margins including $35 million of lower natural gas transportation capacity marketing margins due to less favorable net realized pricing spreads. The decrease in natural gas marketing margins also includes $9 million of lower natural gas storage marketing margins primarily driven by higher storage fees and less favorable realized derivative gains, partially offset by a favorable change of $14 million in lower cost or net realizable value inventory adjustment;

•A $20 million decrease in NGL marketing margins including an unfavorable change in net realized gains and losses on sale of inventory in 2024 compared to 2023 driven by unfavorable changes in non-ethane prices.

Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and Net processing commodity expenses changed from 2023 primarily due to a change in forward commodity prices relative to hedge positions in 2024 compared to 2023.

Other

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(1)    Included as a component of Net realized product sales.

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Management’s Discussion and Analysis (Continued)

2025 vs. 2024

Modified EBITDA from upstream operations, corporate, and other business activities increased primarily due to:

•A $161 million increase in Net realized product sales from upstream operations consisting of a $143 million increase at the Wamsutter region and an $18 million increase at the Haynesville Shale region. The Wamsutter region increased primarily due to higher production volumes, including from the November 2024 Crowheart Acquisition, and higher net realized natural gas prices, partially offset by lower net realized oil and NGL prices. The Haynesville region benefited from higher net realized natural gas prices, partially offset by lower production volumes, associated with South Mansfield production in the Haynesville Shale region;

•A $36 million favorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to hedge positions; partially offset by

•A $57 million unfavorable change in other costs and expenses primarily related to upstream operations, including an increase from the Crowheart Acquisition in November 2024, and an unfavorable change associated with regulatory assets related to the effects of deferred taxes on equity funds used during construction.

2024 vs. 2023

Modified EBITDA from upstream operations, corporate, and other business activities decreased primarily due to:

•A $34 million decrease in Net realized product sales from upstream operations primarily due to lower volumes and lower net realized commodity prices associated with Williams’ South Mansfield production in the Haynesville Shale region, and lower net realized commodity prices associated with Williams’ Wamsutter region. These decreases were partially offset by higher production volumes associated with Williams’ Wamsutter region production, including from the Crowheart Acquisition in the fourth quarter of 2024.

•A $27 million unfavorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to hedge positions in 2024 compared to 2023;

•A $12 million unfavorable change in other costs and expenses primarily related to upstream operations; and

•The absence of a 2023 gain related to a favorable ruling on the final order and judgment of Williams’ complaint against Energy Transfer reflected in Net gain from Energy Transfer litigation judgment (see Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).

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Transco - Results of Operations

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*    + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.

2025 vs. 2024

Variances due to the changes in natural gas prices and transportation volumes have little impact on revenues because, under our rate design methodology, the majority of overall cost of service is recovered through firm capacity reservation charges in Transco’s transportation rates.

Transco has cash out sales, which settle gas imbalances with shippers. In the course of providing transportation services to customers, Transco may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, Transco transports gas on various pipeline systems, which may deliver

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Management’s Discussion and Analysis (Continued)

different quantities of gas on Transco’s behalf than the quantities of gas received from Transco. These transactions result in gas transportation and exchange imbalance receivables and payables. Transco’s tariff includes a method whereby the majority of transportation imbalances are settled on a monthly basis through cash out sales or purchases. The cash out sales have no impact on Transco’s operating income.

Revenues increased primarily due to:

•An increase in Natural gas transportation service revenues primarily due to additional capacity from placing the following projects into service:

◦The Regional Energy Access Expansion in August 2024;

◦The Southside Reliability Enhancement in November 2024;

◦The Texas Louisiana Energy Pathway in April 2025;

◦The Southeast Energy Connector in April 2025;

◦The Commonwealth Energy Connector in November 2025; and

◦The Alabama Georgia Connector in November 2025.

The increase in Natural gas transportation service revenues is also due to transportation rate increases effective March 1, 2025, and higher seasonal services, partially offset by one less billing day in 2025, a decrease in short-term firm transportation, and lower electric power costs in 2025. Electric power costs are recovered from Transco’s customers through transportation rates and are offset in Operating and maintenance expenses resulting in no net impact on Transco’s results of operations.

•An increase in Natural gas storage service revenues primarily due to an increase in rates.

•An increase in Natural gas product sales due to higher cash-out pricing, partially offset by lower volumes, which directly offsets in Natural gas product costs resulting in no net impact on our results of operations.

•An increase in Other service revenues due to higher park and loan services.

Natural gas product costs changed unfavorably, directly offsetting Natural gas product sales and resulting in no net impact on our results of operations.

Operating and maintenance expenses remained consistent year over year primarily due to an increase in employee-related costs offset by the absence of a 2024 change in payroll policy and lower electric power costs. Electric power costs are recovered from customers through transportation rates and are offset in Natural gas transportation service revenues resulting in no net impact on results of operations.

Depreciation and amortization expenses increased due to rate increases effective March 1, 2025, as well as assets added from projects placed into service, partially offset by a decrease in ARO related depreciation (offset in Other income (expense) – net resulting in no net impact on Transco’s results of operations).

General and administrative expenses increased due to higher corporate allocations and employee-related costs, partially offset by the absence of a 2024 change in payroll policy.

Other (income) expense – net changed unfavorably primarily driven by changes in charges and credits associated with the rate case at Transco, and an unfavorable change in the deferral of ARO-related depreciation (offset in Depreciation and amortization expenses resulting in no net impact on Transco’s results of operations).

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Management’s Discussion and Analysis (Continued)

Interest income decreased primarily due to a decrease in affiliated interest income associated with advances to Williams.

Allowance for equity and borrowed funds used during construction (AFUDC) decreased as a result of lower capital expenditures.

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Management’s Discussion and Analysis (Continued)

NWP - Results of Operations

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*    + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.

2025 vs. 2024

Variances due to changes in natural gas prices and transportation volumes have little impact on revenues because, under our rate design methodology, the majority of overall cost of service is recovered through firm capacity reservation charges in NWP’s transportation rates.

Revenues increased primarily due to:

•An increase in Natural gas transportation service revenues primarily due to rate increases effective April 1, 2025, and an increase in long-term firm transportation, partially offset by one less billing day in 2025 and a decrease in short-term firm transportation;

•Partially offset by a decrease in Other service revenues from lower park and loan services.

Depreciation and amortization expenses increased due to additional assets placed in service.

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Management’s Discussion and Analysis (Continued)

General and administrative expenses decreased primarily due to the absence of lease termination expense incurred in the prior year.

Other (income) expense - net decreased primarily due to the recognition of a regulatory liability to be returned to rate payers for excess deferred income taxes.

Allowance for equity and borrowed funds used during construction (AFUDC) decreased as a result of lower capital expenditures.

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Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview

Williams

During 2025, investing and financing expenditures included $4.9 billion of capital expenditures, including the Rimrock, Saber, and Driftwood Pipeline asset purchases as well as Power Innovation projects; $2.4 billion of dividends paid to common shareholders; and $0.5 billion of investments in unconsolidated affiliates, including Cogentrix and Louisiana LNG. These expenditures were funded primarily by $5.9 billion of cash provided by operating activities and $2.4 billion of net borrowing activity in 2025. Williams ended the year with $63 million of Cash and cash equivalents. See also the following section titled Sources (Uses) of Cash.

The June 2025 Saber Asset Purchase included the retention of $113 million of Saber’s debt, which was separately repaid in full within the same month. On January 3, 2025, Williams paid the remaining $100 million of the Gulf Coast Storage Acquisition purchase price obligation (see Note 3 – Acquisitions and Divestitures).

Outlook

Williams’ growth capital and investment expenditures in 2026 are expected to range from $6.1 billion to $6.7 billion, as previously discussed in Company Outlook.

On January 8, 2026, Williams issued $2.8 billion of long-term debt (see Note 13 – Debt and Banking Arrangements).

As of December 31, 2025, Williams, including consolidated subsidiaries, had $1.3 billion of long-term debt due within one year. Williams’ potential sources of liquidity available to address these maturities include cash on hand, proceeds from refinancing, the credit facility, or the commercial paper program, as well as proceeds from asset monetizations.

Liquidity

Williams expects to have sufficient liquidity to manage its businesses in 2026 based on forecasted levels of cash flow from operations and other sources of liquidity. Williams’ potential material internal and external sources and uses of liquidity are as follows:

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As of December 31, 2025, Williams had $27.3 billion of long-term debt due after one year. Potential sources of liquidity available to address these maturities include cash generated from operations, proceeds from refinancing, the credit facility, the commercial paper program, and proceeds from asset monetizations.

Potential risks associated with Williams’ planned levels of liquidity discussed above include those previously discussed in Company Outlook.

As of December 31, 2025, Williams had a working capital deficit of $2.9 billion, including cash and cash equivalents and long-term debt due within one year. As discussed above, Williams issued $2.8 billion of long-term debt in January 2026. Williams’ available liquidity is as follows:

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(1)In managing its available liquidity, Williams does not expect a maximum outstanding amount in excess of the capacity of its credit facility inclusive of any outstanding amounts under its commercial paper program. Williams had $700 million of Commercial paper outstanding at December 31, 2025. Through December 31, 2025, the highest amount outstanding under the commercial paper program and credit facility during 2025 was $898 million. Williams expects to be in compliance with the financial covenants associated with the credit facility for the December 31, 2025, reporting period.

Dividends

Williams increased the regular quarterly cash dividend to common stockholders by approximately 5 percent from $0.475 per share paid in each quarter of 2024, to $0.500 per share paid in each quarter of 2025. On January 27, 2026, Williams’ board of directors approved a regular quarterly dividend of $0.525 per share payable on March 30, 2026.

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Management’s Discussion and Analysis (Continued)

Registrations

In February 2024, Williams filed a shelf registration statement as a well-known seasoned issuer.

Distributions from Equity-Method Investees

The organizational documents of entities in which Williams has an equity-method investment generally require periodic distributions of their available cash to their members. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. See Note 8 – Investing Activities for our more significant equity-method investees.

Credit Ratings

The interest rates at which Williams is able to borrow money are impacted by its credit ratings, which are currently as follows:

These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold Williams securities, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign Williams investment-grade ratings even if it meets or exceeds their current criteria for investment-grade ratios. A downgrade of its credit ratings might increase Williams’ future cost of borrowing and, if ratings were to fall below investment-grade, could require it to provide additional collateral to third parties, negatively impacting Williams’ available liquidity.

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Management’s Discussion and Analysis (Continued)

Sources (Uses) of Cash

The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented in Williams’ Consolidated Statement of Cash Flows:

Operating activities

The factors that determine Williams’ operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation, depletion, and amortization, Provision (benefit) for deferred income taxes, Equity (earnings) losses, Net unrealized (gain) loss from commodity derivative instruments, Gain on sale of business, Impairment or write-off of certain assets, Gain on disposition of equity-method investments, Gain on remeasurement of equity-method investments, Inventory write-downs, and Amortization of stock-based awards.

Williams’ Net cash provided (used) by operating activities in 2025 increased from 2024 primarily due to higher operating income (excluding noncash items previously discussed), along with favorable changes in margin requirements.

Williams’ Net cash provided (used) by operating activities in 2024 decreased from 2023 primarily due to unfavorable changes in margin requirements, lower operating income (excluding noncash items previously discussed), and unfavorable changes in net operating working capital.

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