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Item 7. Management’s Discussion and Analysis

2026-02-24 compared with 2025-02-25 · 370 added, 428 removed, 372 unchanged (68% of the section changed)

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Company Outlook

Critical Accounting Estimates

Results of Operations

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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, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation.

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.

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Williams focuses on consistently attracting new business by providing highly reliable service to its customers.

These services include natural gas gathering, processing, treating, compression and storage;

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’ chief operating decision maker evaluates performance and allocates resources, Williams’ operations are conducted, managed, and presented within the following reportable segments:

Transmission & Gulf of America, Northeast G&P, West, and Gas & NGL Marketing Services.

All remaining business activities, including upstream operations, certain new energy ventures, and corporate activities, are included in Other.

Williams’ reportable segments are comprised of the following business activities:

• Transmission & Gulf of America is comprised of the Transco, NWP, and MountainWest interstate natural gas pipelines, and their related natural gas storage facilities, as well as natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, includ ing Discovery, a former 60 percent equity-method investment in which Williams acquired the remaining ownership interest in August 2024 (see Note 3 – Acquisitions and Divestitures), a 51 percent interest in Gulfstar One, and a 50 percent equity-method investment in Gulfstream.

Transmission & Gulf of America also includes natural gas storage facilities and pipelines providing services in north Texas, and also in Louisiana and Mississippi related to the January 2024 Gulf Coast Storage Acquisition (see Note 3 – Acquisitions and Divestitures).

• Northeast G&P is comprised of midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in Northeast JV which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal which operates in Ohio, a 69 percent equity-method

Management’s Discussion and Analysis (Continued)

investment in Laurel Mountain, a 50 percent equity-method investment in Blue Racer, and Appalachia Midstream Investments.

• West is comprised of gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of east Texas and northwest Louisiana, the Mid-Continent region which includes the Anadarko and Permian basins, and the DJ Basin of Colorado which includes RMM, a former 50 percent equity-method investment in which Williams acquired the remaining ownership interest in November 2023 (see Note 3 – Acquisitions and Divestitures).

This segment also includes NGL storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in OPPL.

• Gas & NGL Marketing Services is comprised of NGL and natural gas marketing and trading operations, which includes risk management and transactions related to the storage and transportation of natural gas and NGLs on strategically positioned assets.

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 notes thereto included in Part II, Item 8 of this report.

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;

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.

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.

Management’s Discussion and Analysis (Continued)

Overview of Year Ended December 31, 2025

Net income (loss) attributable to The Williams Companies, Inc.

for the year ended December 31, 2024, decreased $954 million compared to the year ended December 31, 2023.

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.

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Transco FERC Rate Case Filing

On August 30, 2024, Transco filed a general rate case with the FERC for an overall increase in rates.

In September 2024, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended 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 specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2024, as requested by Transco, and will not be subject to refund.

The impact of the rates reflecting a rate decrease is expected to reduce revenues by approximately $1 million per month beginning October 1, 2024.

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.

Management’s Discussion and Analysis (Continued)

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

Significant expansion project updates for the period, including projects placed into service are described below.

Expansion projects placed into service for the current year are described below.

Ongoing major expansion projects are discussed later in Company Outlook.

Transmission & Gulf of America

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

Management’s Discussion and Analysis (Continued)

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

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

Management’s Discussion and Analysis (Continued)

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.

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.

Southside Reliability Enhancement

In July 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 Virginia and North Carolina to delivery points in North Carolina.

This project went into service in the fourth quarter of 2024.

The project increased capacity by 423 Mdth/d.

Regional Energy Access

In January 2023, Transco received approval from the FERC for the project to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in northeastern Pennsylvania to multiple delivery points in Pennsylvania, New Jersey, and Maryland.

Transco placed approximately half of the project into service in the fourth quarter of 2023 and placed the remainder of the project into service in August 2024.

The project increased capacity by 829 Mdth/d.

On January 24, 2025, the FERC issued an Order on Remand Reinstating Certificate and Abandonment Authorization (Remand Order) for the project.

The Remand Order was issued in response to the D.C.

Circuit Court of Appeals’ decision in New Jersey Conservation Foundation, et al., v.

FER C, which vacated the FERC certificate order for the project and remanded the matter to the FERC for appropriate action.

In the Remand Order, the FERC (1) continued to find that the project is needed, (2) affirmed its decision not to make a significance determination regarding greenhouse gas emissions, (3) considered Transco’s measures to reduce greenhouse gas emissions, and (4) concluded that the benefits of the project outweigh the adverse impacts.

Accordingly, the Remand Order reinstated the certificate and abandonment authority for the project as issued in the FERC’s original certificate order.

The authorization took effect upon the issuance of the mandate by the D.C.

Circuit Court of Appeals, which occurred on January 29, 2025.

Data Center Power Projects

Williams continues to pursue projects to support the power demands created by new data center development.

Williams is in the process of ordering major equipment and long-lead time items for the most mature of these expected projects.

These advanced purchases are supported by reimbursement agreements from the potential customer.

Acquisitions and Divestitures

Crowheart Acquisition

As of December 31, 2023, Williams had an agreement regarding certain crude oil and natural gas properties in the Wamsutter basin in Wyoming under which it owned a 75 percent undivided interest in each well’s working interest and proportionally consolidated its undivided interest.

On November 1, 2024, Williams closed on the acquisition of a third-party operator, Crowheart Energy, LLC, for $307 million cash, subject to working capital and post-closing adjustments.

After closing on the acquisition, Williams owns more than a 90 percent working interest in each well.

The purpose of this acquisition was to consolidate Williams’ interests in the Wamsutter basin and further optimize development in the area to continue to supply its gathering and processing assets (see Note 3 – Acquisitions and Divestitures).

Discovery Acquisition

As of December 31, 2023, Williams owned a 60 percent interest in Discovery, which it accounted for as an equity-method investment.

On August 1, 2024, Williams closed on the acquisition of the remaining 40 percent interest in Discovery, along with certain other assets, for $170 million cash, subject to working capital and post-closing adjustments.

As a result of acquiring this additional interest, Williams obtained control and subsequently consolidates Discovery.

Williams recognized a $127 million gain on remeasuring its existing equity-method

Management’s Discussion and Analysis (Continued)

investment to fair value included in Other investing income (loss) – net in the Consolidated Statement of Income in the third quarter of 2024.

The purpose of this acquisition was to expand Williams’ gathering, processing, and transportation presence in the Gulf of America region.

Discovery continues to be reported within the Transmission & Gulf of America segment (see Note 3 – Acquisitions and Divestitures).

Sale of Aux Sable interest

Also on August 1, 2024, Williams completed the sale of its equity-method investments in Aux Sable in Williams’ Northeast G&P segment for total consideration of $161 million.

As a result of this sale, Williams recorded a gain of $149 million included in Other investing income (loss) – net in the Consolidated Statement of Income in the third quarter of 2024 (see Note 8 – Investing Activities).

Gulf Coast Storage Acquisition

On January 3, 2024, Williams closed on the acquisition from Hartree Partners LP for $1.95 billion of 100 percent of a strategic portfolio of natural gas storage facilities and pipelines, located in Louisiana and Mississippi.

The purpose of this acquisition, which is reported in the Transmission & Gulf of America segment, was to expand Williams’ natural gas storage footprint in the Gulf Coast region.

The Gulf Coast Storage Acquisition was funded with cash on hand and $100 million of deferred consideration.

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).

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

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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 us to deliver safe, reliable, clean energy services to its customers and an attractive return to shareholders.

Williams believes that accomplishing these goals will position it

Management’s Discussion and Analysis (Continued)

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 2025, Williams’ operating results are expected to benefit from the continued growth in the Transmission & Gulf of America segment, primarily reflecting the impacts of numerous expansion projects at Transco and the Gulf of America.

Additionally, growth in 2025 includes the impact of the Transco rate case and higher gathering and processing results associated with growth in the DJ Basin and the Northeast.

Williams also expects increases in Haynesville Shale volumes, including partial year impact of the Louisiana Energy Gateway expansion project and higher expected results from its upstream operations, including the full year impact of the Crowheart Acquisition.

These increases are partially offset by a modest increase in expenses and lower expected Eagle Ford results in our West segment related to minimum volume commitment reductions.

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 2025 are expected to range from $1.65 billion to $1.95 billion, excluding acquisitions.

Growth capital spending in 2025 primarily includes projects supporting growth in the Haynesville Shale basin (including the Louisiana Energy Gateway expansion project), Transco expansions, all of which are fully contracted with firm transportation agreements, and projects supporting the Northeast G&P business.

Williams also expects to invest capital in the development of its upstream oil and gas properties.

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.

Management’s Discussion and Analysis (Continued)

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:

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Risk Factors.

Management’s Discussion and Analysis (Continued)

Expansion Projects

Williams’ ongoing major expansion projects include the following:

Transmission & Gulf of America

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 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 facilities at Larose, Louisiana to handle the expected rich Shenandoah production, and the natural gas liquids will be fractionated and marketed at Discovery’s Paradis plant in Louisiana.

Williams plans to place the project into service in the second quarter of 2025.

Overthrust Westbound Compression Expansion

MountainWest plans to place the project into service as early as the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals.

The project is expected to increase capacity by 325 Mdth/d.

Texas to Louisiana Energy Pathway

Transco plans to place the project into service during the first quarter of 2025, assuming timely receipt of all necessary regulatory approvals.

The project is expected to provide 364 Mdth/d of new firm transportation service through a combination of increasing capacity, converting interruptible capacity to firm, and utilizing existing capacity.

Management’s Discussion and Analysis (Continued)

Southeast Energy Connector

Transco plans to place the project into service in the second quarter of 2025, assuming timely receipt of all necessary regulatory approvals.

Transmission, Power & Gulf

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.

Commonwealth Energy Connector

Transco plans to place the project into service as early as the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals.

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.

Alabama Georgia Connector

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.

Southeast Supply Enhancement

In October 2024, Transco filed a certificate 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 Virginia to delivery points in Virginia, North Carolina, South Carolina, Georgia, and Alabama.

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

Management’s Discussion and Analysis (Continued)

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.

Transco plans to file the prior notice application for the project with the FERC in 2025, 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 fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals.

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

NWP plans to file the prior notice application for the project with the FERC in 2025.

The Ryckman Creek Loop expansion involves an expansion of NWP’s existing natural gas transmission system to provide incremental firm transportation capacity from a receipt point in northeast Oregon (Stanfield) to multiple delivery points in southwest Wyoming.

NWP plans to place the project into service as early as the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals.

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.

Stanfield South Project

The Stanfield South Project on NWP’s existing natural gas transmission system will provide year-round transportation capacity from the Stanfield receipt point in Oregon to multiple delivery points in Idaho.

NWP plans to place the project into service as early as the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals.

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.

Management’s Discussion and Analysis (Continued)

Naughton Coal-to-Gas Conversion

The Naughton Coal-to-Gas Conversion project on NWP’s existing natural gas transmission system will 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.

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 Project

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 file the certificate application with the FERC in 2025.

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.

Huntingdon Connector

The Huntingdon Connector project on NWP’s existing natural gas transmission system will provide year-round transportation capacity from the Sumas receipt point to various delivery points in Washington.

NWP plans to file the prior notice application for the project with the FERC in 2026.

NWP plans to place the project in service during the fourth quarter of 2026, assuming timely receipt of all necessary regulatory approvals.

The project is expected to increase capacity by 87 Mdth/d.

Wild Trail Expansion

The Wild Trail Expansion project on NWP’s existing natural gas transmission system 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.

This project is fully subscribed by an affiliate within Williams’ Gas & NGL Marketing Services segment.

NWP plans to file the certificate application with the FERC in 2025.

NWP plans to place the project in 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.

Louisiana Energy Gateway

In August 2024, Williams began construction activities on new natural gas gathering assets which are expected to gather 1.8 Bcf/d of natural gas produced in the Haynesville Shale basin for delivery to premium markets, including Transco, industrial markets, and growing LNG export demand along the Gulf Coast.

This project is expected to go into service in the third quarter of 2025.

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.

Williams is constructing a greenfield gathering system in support of the third party’s 26,000-acre dedication.

The system, once completed, will provide natural gas gathering services to the third party.

The third party has also agreed to a long-term capacity commitment on Williams’ Louisiana Energy Gateway expansion project.

This project is expected to go into service in third quarter 2025.

Power Innovation

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

Management’s Discussion and Analysis (Continued)

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.

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

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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.

Management’s Discussion and Analysis (Continued)

Williams’ Pension and Postretirement Obligations

Williams has pension and other postretirement benefit plans that require the use of assumptions and estimates to determine the benefit obligations and costs.

These estimates and assumptions involve significant judgment and actual results will likely be different than anticipated.

Estimates and assumptions utilized include the expected long-term rates of return on plan assets, discount rates, cash balance interest crediting rate, and employee demographics, including retirement age and mortality.

These assumptions are reviewed annually and adjustments are made as needed.

The assumptions utilized to compute the benefit obligations and costs are shown in Note 7 – Employee Benefit Plans.

The following table presents the estimated increase (decrease) in net periodic benefit cost and obligations resulting from a one-percentage-point change in the specific assumption.

Benefit Cost Benefit Obligation

Increase One-

Decrease One-

Increase One-

Pension benefits:

Discount rate

$ 3 $ (4) $ (62) $ 71

Expected long-term rate of return on plan assets

Cash balance interest crediting rate

4 (4) 45 (39)

Other postretirement benefits:

Discount rate

(3) 3 (11) 14

Expected long-term rate of return on plan assets

Williams’ expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on historical returns, forward-looking capital market expectations of at least 10 years from Williams’ third-party independent investment advisor, as well as the investment strategy and relative weightings of the asset classes within the investment portfolio.

Williams’ expected long-term rate of return on plan assets used for Williams’ pension plans was 5.31 percent in 2024.

The 2024 actual return on plan assets for Williams’ pension plans was approximately 8.0 percent.

The 10-year average rate of return on pension plan assets through December 2024 was approximately 6.6 percent.

The expected rates of return on plan assets are long-term in nature and are not significantly impacted by short-term market performance.

The discount rates for Williams’ pension and other postretirement benefit plans are determined separately based on an approach specific to Williams’ plans, which considers a yield curve of high-quality corporate bonds and the duration of the expected benefit cash flows of each plan.

The cash balance interest crediting rate assumption represents the average long-term rate by which the pension plans’ cash balance accounts are expected to grow.

Interest on the cash balance accounts is based on the 30-year U.S.

Treasury securities rate.

Regulatory Accounting

Transco and NWP are regulated by the FERC.

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.

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Management’s expected recovery of deferred costs and return of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment.

Transco and NWP record certain incurred costs and obligations 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.

Management’s Discussion and Analysis (Continued)

Accounting for businesses that are regulated and apply the provisions of ASC 980 can differ from the accounting requirements for non-regulated businesses.

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 (ARO) and other costs and taxes included in, or expected to be included in, future rates.

As rate-regulated entities, Transco’s and NWP’s management has determined that 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.

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, either Transco or NWP ceases to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Balance Sheet and included in the Statement of Net 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.

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

Management’s Discussion and Analysis (Continued)

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 Transco’s and NWP’s Balance Sheets at December 31, 2024, is $394 million and $55 million, respectively.

The aggregate amount of regulatory liabilities reflected on Transco’s and NWP’s Balance Sheets at December 31, 2024, is $1.0 billion and $253 million, respectively.

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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Operating and maintenance expenses 2,282 -103 -5 % 2,179 -195 -10 % 1,984

Depreciation and amortization expenses 2,219 -148 -7 % 2,071 -62 -3 % 2,009

Selling, general, and administrative expenses 708 -43 -6 % 665 -29 -5 % 636

Gain on sale of business — -129 -100 % (129) +129 NM —

Other (income) expense – net (60) +30 +100 % (30) +58 NM 28

Depreciation, depletion, and amortization expenses

2,347 -128 -6 % 2,219 -148 -7 % 2,071

General and administrative expenses 721 -13 -2 % 708 -43 -6 % 665

Impairment or write-off of certain assets 212 -212 NM — +10 +100 % 10

Gain on sale of business — — — — -129 -100 % (129)

Other (income) expense – net (7) -53 -88 % (60) +20 +50 % (40)

Total costs and expenses 7,754 7,164 6,596

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Equity earnings (losses) 760 +200 +36 % 560 -29 -5 % 589

Other investing income (loss) – net 343 +235 NM 108 +92 NM 16

Other investing income (loss) – net 42 -301 -88 % 343 +235 NM 108

Interest expense (1,442) -78 -6 % (1,364) -128 -10 % (1,236)

Net gain from Energy Transfer litigation judgment — -534 -100 % 534 +534 NM —

Other income (expense) – net 108 +9 +9 % 99 +81 NM 18

Net gain from Energy Transfer litigation judgment — — — — -534 -100 % 534

Other income (expense) – net 69 -39 -36 % 108 +9 +9 % 99

Income (loss) before income taxes

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Provision (benefit) for income taxes 857 -217 -34 % 640 +365 +36 % 1,005

640 +365 +36 % 1,005 -580 -136 % 425

Income (loss) from continuing operations 2,768 2,346 3,400

Income (loss) from discontinued operations — +97 +100 % (97) -97 NM —

Income (loss) from discontinued operations — — — — +97 +100 % (97)

Net income (loss) 2,768 2,346 3,303

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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 & Gulf of America segment;

partially offset by lower volumes from the September 2023 sale of certain liquids pipelines at the Transmission & Gulf of America segment (See Note 3 – Acquisitions and Divestitures),

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

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

• 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 .

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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 & Gulf of America segment primarily related to the Discovery Acquisition, as previously discussed;

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, as previously discussed.

• 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.

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.

Management’s Discussion and Analysis (Continued)

Service revenues increased primarily due to:

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 & Gulf of America segment;

• 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 (See Note 3 – Acquisitions and Divestitures);

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 & Gulf of America segment primarily due to the Discovery Acquisition, as previously discussed.

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 at Other (see Note 17 – Commodity Derivatives).

However, the unrealized fair value measurement gains and losses 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.

Management’s Discussion and Analysis (Continued)

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 & Gulf of America segment primarily related to the Discovery Acquisition, as previously discussed;

• 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;

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• 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 & Gulf of America segments;

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 and amortization expenses increased primarily related to the assets acquired at the Transmission & Gulf of America and West segments and an increase at Transco related to additional assets placed in service.

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.

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(Sequent) in 2021.

Selling, 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 & Gulf of America segment in 2023, as previously discussed.

Other (income) expense – net within Operating income (loss) includes lower project feasibility costs at our Transmission & Gulf of America 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, as previously discussed, 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, as previously discussed, 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, as previously discussed, partially offset by 2023 and 2024 debt retirements (see Note 13 – Debt and Banking Arrangements).

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 – General, 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 Williams’ estimate of the state deferred income tax rate in both periods.

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.

Management’s Discussion and Analysis (Continued)

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 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).

Service revenues increased primarily due to:

• Higher volumes from acquisitions at the Transmission & Gulf of America segment;

• Higher volumes and rates at the Northeast G&P segment;

partially offset by

• Lower rates, partially offset by higher volumes at the West segment.

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

• Lower marketing sales activities at the Gas & NGL Marketing Services segment;

• Lower sales from upstream operations at Other;

• Lower equity NGL sales prices primarily at the West and Transmission & Gulf of America segments;

• Lower system management gas sales primarily at the West and Transmission & Gulf of America segments.

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

• Lower marketing activities at the Gas & NGL Marketing Services segment;

• Lower costs associated with NGLs acquired as commodity consideration related to Williams’ equity NGL production activities;

• Lower system management gas purchases primarily at the West and Transmission & Gulf of America segments.

• Unfavorable change in unrealized gains and losses from commodity derivatives related to processing plant shrink gas purchases;

• Partially offset by lower natural gas purchases due to lower prices associated with Williams’ equity NGL production activities primarily at the West and Transmission & Gulf of America segments.

Operating and maintenance expenses increased primarily due to higher operating costs, including increased costs associated with the February 2023 MountainWest Acquisition, the April 2022 Trace Acquisition, and the August 2022 NorTex Asset Purchase, and increased scope and timing of operating and maintenance activities.

Depreciation and amortization expenses increased primarily related to the upstream assets, and assets acquired in the February 2023 MountainWest Acquisition, the April 2022 Trace Acquisition, and the August 2022 NorTex Asset Purchase.

The increase is partially offset by lower amortization of intangibles related to the acquisition of Sequent in 2021.

Selling, general, and administrative expenses increased primarily due to acquisition and transition-related costs associated with the MountainWest Acquisition.

Management’s Discussion and Analysis (Continued)

Gain on sale of business resulted from the sale of certain liquids pipelines in the Gulf Coast region, as previously discussed.

Other (income) expense – net within Operating income (loss) changed favorably primarily due to:

• A favorable change associated with regulatory liabilities established for the impacts of deferred income taxes at NWP and the absence of 2022 regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate;

• The absence of a 2022 loss related to Eminence storage cavern abandonments;

• A 2023 gain related to a contract settlement.

Equity earnings (losses) changed unfavorably primarily due to a decrease at Laurel Mountain and the share of a loss contingency accrual related to the 14 percent ownership in Aux Sable, partially offset by increases at Blue Racer and OPPL.

The favorable change in Other investing income (loss) – net includes higher interest income earned on higher cash and cash equivalent balances, and a gain on remeasuring the existing equity-method investment in RMM, as previously discussed.

The increase in Interest expense was primarily due to Williams’ 2023 debt issuances and MountainWest’s long-term debt, partially offset by an increase in interest capitalized related to ongoing expansion projects.

Net gain from Energy Transfer litigation judgment resulted from a favorable ruling on the final order and judgment of Williams’ complaint against Energy Transfer, as previously discussed.

The favorable change in Other income (expense) – net below Operating income (loss) includes an increase in equity allowance for funds used during construction (equity AFUDC) at the Transmission & Gulf of America segment and the related effects of deferred taxes within Other.

Income (loss) from discontinued operations in 2023 includes a pre-tax charge of $125 million to increase the accrued liability associated with our Alaska refinery contamination litigation, partially offset by the related income tax effect.

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income, the absence of a benefit related to the release of valuation allowances on deferred income tax assets in 2022, a lower benefit associated with decreases in the Williams’ estimate of the state deferred income tax rate in both periods, and the absence of 2022 federal income tax settlements.

The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to higher results at Cardinal and the Northeast JV.

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’ chief operating decision maker 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 from continuing operations .

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.

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Management’s Discussion and Analysis (Continued)

Transmission & Gulf of America

Transmission , Power & Gulf

Year Ended December 31,

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Proportional Modified EBITDA of equity-method investments 147 173 205

Transmission & Gulf of America Modified EBITDA $ 3,273 $ 3,068 $ 2,674

Transmission, Power & Gulf Modified EBITDA $ 3,720 $ 3,273 $ 3,068

Commodity margins $ 68 $ 53 $ 33

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(1) Included as a component of Commodity margins .

Transmission & Gulf of America 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.

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.

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.

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 (see Note 3 – Acquisitions and Divestitures);

• 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);

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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, as previously discussed;

partially offset by significantly

Management’s Discussion and Analysis (Continued)

employee-related costs, including the impact of a change in a practice related to payroll timing;

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

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;

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• 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, as previously discussed.

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

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

Transmission & Gulf of America Modified EBITDA increased primarily due to higher Service revenues and a Gain on sale of business.

Service revenues increased primarily due to:

• A $222 million increase due to the acquisition of MountainWest primarily in transportation and storage revenues;

• A $42 million increase due to the NorTex Asset Purchase primarily in storage and transportation revenues;

• A $30 million increase in the Eastern Gulf Coast region primarily due to higher production handling volumes from new wells at Devils Tower, partially offset by lower volumes from the Norphlet pipeline due to natural decline;

• A $15 million increase in Transco’s revenues associated with the Regional Energy Access expansion project placed partially in-service in the fourth quarter of 2023;

• A $12 million increase in Transco’s and Northwest Pipeline’s revenues associated with short-term firm transportation;

partially offset by

• A $19 million decrease due to lower rates from the FERC rate case settlement effective January 1, 2023, at Northwest Pipeline;

• A $14 million decrease in reimbursable electric power costs and storage rates, offset by similar changes in electricity charges and storage costs, reflected in Other segment costs and expenses;

• A $10 million decrease due to the sale of certain liquids pipelines in the Gulf Coast region in September 2023 primarily in transportation revenues.

Commodity margins decreased primarily due to a $15 million decrease from Williams’ equity NGLs, driven by unfavorable net realized pricing for equity NGL sales, partially offset by lower prices for natural gas purchases associated with its equity NGL production activities.

Management’s Discussion and Analysis (Continued)

Other segment costs and expenses increased primarily due to:

• Higher operating and administrative costs including higher operating, acquisition, and transition costs related to Williams’ MountainWest Acquisition and NorTex Asset Purchase;

and higher costs related to timing and scope of general maintenance activities primarily at Transco, partially offset by lower reimbursable electric power costs and storage costs, which are offset by a similar change in electricity reimbursements and storage revenues reflected in Service revenues ;

and lower employee-related costs;

• Higher project feasibility costs;

partially offset by

• Favorable changes associated with regulatory liabilities established for the impacts of deferred income taxes at Northwest Pipeline associated with the FERC rate case settlement mentioned above in Service revenues and the absence of 2022 regulatory charges associated with decreases in Transco’s estimated deferred state income tax rate;

• A favorable change in equity AFUDC as a result of increased capital expenditures at Transco;

• The absence of losses related to Eminence storage cavern abandonments in 2022.

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

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

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Northeast G&P Modified EBITDA

$ 2,028 $ 1,958 $ 1,916

Commodity margins $ 24 $ 24 $ 12

(1) Included as a component of Commodity margins .

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

Management’s Discussion and Analysis (Continued)

• 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.

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.

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• 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;

Management’s Discussion and Analysis (Continued)

• 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);

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

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

Service revenues increased primarily due to:

• A $92 million increase in revenues at the Northeast JV primarily related to higher transportation & fractionation, processing, and gathering volumes as well as higher processing rates;

• An $84 million increase in revenues in the Utica Shale region primarily related to higher gathering rates resulting from annual cost-of-service contract redeterminations and higher volumes, partially offset by the absence of proceeds from the release of an acreage dedication in 2022;

• A $61 million increase in gathering revenues at Susquehanna Supply Hub primarily related to escalated rates as well as higher volumes.

Other segment costs and expenses increased primarily due to increased scope of operations, a loss contingency accrual, and higher operating taxes.

Proportional Modified EBITDA of equity-method investments decreased at Laurel Mountain due to lower commodity-based gathering rates, MVC, and volumes, and at Aux Sable Liquid Products LP primarily due to Williams’ $31 million share of a loss contingency accrual related to its former ownership in 2023.

The decrease was partially offset by an increase at Blue Racer primarily driven by higher gathering and processing volumes.

Additionally, Appalachia Midstream Investments increased primarily driven by higher gathering volumes and

Additionally, Appalachia

Management’s Discussion and Analysis (Continued)

annual rate escalations at Marcellus South, partially offset by lower gathering rates resulting from annual cost-of-service contract redeterminations and lower volumes at the Bradford Supply Hub.

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

Year Ended December 31,

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Other segment costs and expenses (663) (645) (532)

Impairment or write-off of certain assets (212) — (10)

Proportional Modified EBITDA of equity-method investments 142 132 162

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(1) Included as a component of Commodity margins .

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.

Management’s Discussion and Analysis (Continued)

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.

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.

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

Management’s Discussion and Analysis (Continued)

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

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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.

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

Service revenues decreased primarily due to:

• A $120 million decrease in the Barnett Shale region primarily due to lower gathering rates driven by unfavorable commodity pricing;

• A $13 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenues, partially offset by escalated gathering rates and higher gathering volumes;

• A $6 million decrease associated with reimbursable compressor power and fuel purchases primarily due to lower prices, which are offset by similar changes in Other segment costs and expenses ;

partially offset by

• A $69 million increase in the Haynesville Shale region primarily associated with higher gathering volumes including from increased producer activity and the Trace Acquisition in April 2022, partially offset by lower rates driven by unfavorable commodity pricing;

• A $25 million increase in the DJ Basin region primarily associated with the DJ Basin Acquisitions in November 2023 as previously discussed;

• A $15 million increase in our other NGL operations associated with higher storage fees primarily due to a new contract as well as higher fractionation fees primarily due to higher volumes partially offset by lower rates from lower natural gas prices.

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

Commodity margins decreased $68 million primarily due a $46 million decrease from Williams’ equity NGLs and a $14 million decrease from other sales activities, both primarily due to lower net realized commodity pricing.

Management’s Discussion and Analysis (Continued)

Other segment costs and expenses decreased primarily due to a favorable change in Williams’ net imbalance liability due to changes in pricing, favorable contract settlements in first-quarter 2023, lower corporate allocations, and lower reimbursable compressor power and fuel purchases which are substantially offset in Service revenues.

These items were partially offset by higher operating expenses related to operations including those acquired in the Trace Acquisition and the DJ Basin Acquisitions, lower system gains at Wamsutter, and a fourth quarter 2023 write-down of assets held for sale.

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

Gas & NGL Marketing Services

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Other segment costs and expenses (91) (108) (99)

Proportional Modified EBITDA of equity-method investments 36 — —

Gas & NGL Marketing Services Modified EBITDA $ 311 $ (124) $ 950

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(1) Included as a component of Commodity margins .

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 .

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:

• A $44 million decrease in Williams’ 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 its 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 Williams’ 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.

• 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 de creased primarily due to lower employee-related costs.

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

Management’s Discussion and Analysis (Continued)

The change in 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 2023 is primarily due to a change in forward commodity prices relative to Williams’ hedge positions in 2024 compared to 2023.

Gas & NGL Marketing Services Modified EBITDA increased primarily due to a favorable change in Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and higher Commodity margins , partially offset by an unfavorable change in Net unrealized gain (loss) from commodity derivative instruments within Net processing commodity expenses .

Commodity margins increased $66 million primarily due to:

• A $65 million increase from Williams’ natural gas marketing operations including $129 million of higher natural gas storage marketing margins primarily driven by a favorable change of $111 million in lower of cost or net realizable value adjustment;

and the absence of a $15 million charge related to the remaining recognition of a purchase accounting inventory fair value adjustment in 2022.

The increase in its natural gas marketing margins was partially offset by $64 million of lower natural gas transportation capacity marketing margins due to less favorable net realized pricing spreads;

• A $1 million increase in Williams’ NGL marketing margins including a $20 million favorable change in lower of cost or net realizable value inventory adjustments, partially offset by higher transportation and fractionation fees and an unfavorable change in net realized gains and losses on sale of inventory in 2023 compared to 2022 driven by an unfavorable change in NGL prices.

Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and Net processing commodity expenses .

The change from 2022 is primarily due to a change in forward commodity prices relative to Williams’ hedge positions in 2023 compared to 2022.

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.

Year Ended December 31,

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Management’s Discussion and Analysis (Continued)

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.

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

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

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

Modified EBITDA from upstream operations, corporate, and other business activities increased primarily due to the Net gain from Energy Transfer litigation judgmen t, as previously discussed, partially offset by lower results from Williams’ upstream operations, which included the following:

• A $113 million decrease in Net realized product sales primarily due to lower net realized commodity prices, partially offset by higher sales associated with increased production volumes.

Higher natural gas production volumes from new wells in the Haynesville Shale region and higher crude oil production volumes from new wells in the Wamsutter region were partially offset by lower natural gas and NGL production volumes in the Wamsutter region driven by the impact of severe winter weather in 2023;

• A $24 million unfavorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to Williams’ hedge positions in 2023 compared to 2022;

partially offset by

• An increase in Other costs and expenses associated with upstream operations primarily due to increased production volumes and expenses related to severe winter weather in 2023, partially offset by lower associated ad valorem and production taxes, which were impacted by lower commodity prices and lower natural gas and NGL production volumes in the Wamsutter region.

Other costs and expenses not associated with upstream operations decreased primarily due to the absence of an $11 million charge related to an accrual for loss contingency in the third quarter of 2022 and a $19 million favorable change associated with regulatory assets related to the effects of deferred taxes on equity funds used during construction.

• 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).

Management’s Discussion and Analysis (Continued)

Transco - Results of Operations

Year Ended December 31,

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Operating and maintenance expenses 509 +1 — % 510

Selling, general, and administrative expenses 216 -1 — % 215

Depreciation and amortization expenses 574 -29 -5 % 545

General and administrative expenses 223 -7 -3 % 216

Taxes, other than income taxes 114 -3 -3 % 111

Other (income) expense – net (35) -3 -8 % (38)

Other (income) expense – net 27 -62 NM (35)

Total costs and expenses 1,573 1,465

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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 different quantities of gas on Transco’s behalf than the quantities of gas received from Transco.

These transactions

Additionally, Transco transports gas on various pipeline systems, which may deliver

Management’s Discussion and Analysis (Continued)

result in gas transportation and exchange imbalance receivables and payables.

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.

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Revenues increased primarily due to:

• A $113 million increase in Natural gas transportation service revenues due to additional capacity from placing the Regional Energy Access Expansion into service during the fourth quarter of 2023 and in August 2024, the impact of placing the Carolina Market Link Expansion into service during the first quarter of 2024, the impact of placing partially the Southside Reliable Enhancement into service in November 2024, and an additional billing day, partially offset by lower electric power costs in 2024.

Electric power costs are recovered from our customers through transportation rates and are offset in Operating and maintenance expenses resulting in no net impact on our results of operations;

• A $14 million increase in Natural gas storage service revenues primarily due to an increase in rates and an additional billing day;

• A $19 million decrease in Natural gas product sales due to lower pricing offset by higher cash-out volumes, which directly offsets in Natural gas product costs resulting in no net impact on our results of operations;

• A $10 million decrease in Other service revenues primarily due to park and loan services.

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

Operating and maintenance expenses decreased primarily due to lower electric power costs.

• 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;

◦ 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.

additionally there were increases in Operating and maintenance expenses costs from employee-related costs, including the impact of a change in a practice related to payroll timing, offset by a decrease in contractor services costs.

Depreciation and amortization expenses increased as a result of additional assets placed in service and an increase in ARO-related depreciation (offset in Other income (expense) – net resulting in no net impact on our results of operations).

Taxes, other than income taxes increased primarily due to an increase in property tax as a result of valuation increases in 2024.

Other (income) expense – net incurred an unfavorable change primarily driven by an unfavorable change in the amortization of the regulatory pension liabilities, partially offset by a favorable change in the materials and supplies obsolete inventory reserve and a favorable change associated with the deferral of ARO related depreciation (offset in Depreciation and amortization expenses resulting in no net impact on our results of operations).

Interest income decreased due to a decrease in affiliated interest income on our advances to Williams due to a lower note receivable balance during 2024.

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

Other income (expense) – net increased resulting from various increased expenses incurred in 2024.

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).

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.

Management’s Discussion and Analysis (Continued)

NWP - Results of Operations

Year Ended December 31,

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Operating and maintenance expenses 96 -1 -1 % 95

Selling, general, and administrative expenses 51 — — % 51

Depreciation and amortization expenses 117 -6 -5 % 111

General and administrative expenses 49 +2 +4 % 51

Taxes, other than income taxes 15 -1 -7 % 14

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

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 our transportation rates.

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:

• A $1 million increase in Natural gas transportation service revenues primarily due to an additional billing day in the leap year;

• A $3 million increase in Other service revenues from higher park and loan services.

• 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.

Management’s Discussion and Analysis (Continued)

Operating and maintenance expenses increased due to higher labor costs, electricity expenses, and higher contract services related to pipeline maintenance inspection activities.

Allowance for equity and borrowed funds used during construction (AFUDC) increased due to increased capital expenditures in 2024.

Other income (expense) – net decreased due to lower interest income earned on NWP’s advances to affiliates, which had a reduced balance in 2024.

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.

Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity

During 2024, investing and financing expenditures included $2.6 billion of capital expenditures, $2.2 billion of acquisitions including Gulf Coast Storage, Discovery, and Crowheart, and $2.3 billion of dividends paid to common shareholders.

These expenditures were funded primarily by $4.974 billion of cash provided by operating activities.

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 .

Transco and NWP

Transco and NWP fund their capital requirements with cash flows from operating activities, equity contributions and advances from Williams, accessing capital markets, and, if required, borrowings under the credit facility (see Note 13 – Debt and Banking Arrangements).

Transco and NWP may raise capital through private debt offerings, as well as offerings registered pursuant to offering-specific registration statements.

Interest rates, market conditions, and industry conditions will affect amounts raised, if any, in the capital markets.

Transco and NWP anticipate that they will be able to access public and private debt markets on terms commensurate with their credit ratings to finance their capital requirements, when needed.

Transco and NWP are also participants in Williams’ cash management program, and both make advances to and receive advances from Williams.

At December 31, 2024, Transco’s advances to Williams totaled approximately $638 million and NWP’s advances from Williams totaled approximately $26 million.

These advances are represented by demand notes.

See Note 4 – Related Party Transactions.

Growth capital and investment expenditures in 2025 are expected to range from $1.65 billion to $1.95 billion, excluding acquisitions.

Growth capital spending in 2025 primarily includes projects supporting growth in the Haynesville Shale basin (including Louisiana Energy Gateway expansion project), Transco expansions, all of which are fully contracted with firm transportation agreements and projects supporting the Northeast G&P business.

Williams also expects to invest capital in the development of its upstream oil and gas properties.

Williams intends to fund substantially all planned 2025 capital spending with cash available after paying dividends.

Williams retains the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities including the repurchase of its common stock.

On January 9, 2025, Williams issued $1.5 billion of long-term debt and on January 15, 2025, Williams retired $750 million of long term debt (see Note 13 – Debt and Banking Arrangements).

As of December 31, 2024, Williams has approximately $1.7 billion of long-term debt due within one year.

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).

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.

Transco and NWP

Transco and NWP categorize their capital expenditures as either maintenance capital expenditures or growth capital expenditures.

Maintenance capital expenditures are those expenditures required to maintain the existing

Management’s Discussion and Analysis (Continued)

operating capacity and service capability of their assets, including replacement of system components and equipment that are worn, obsolete, completing their useful life, or necessary to remain in compliance with environmental laws and regulations.

Growth capital expenditures improve the service capability of existing assets, extend useful lives, increase transmission or storage capacities from existing levels, reduce costs or enhance revenues.

Transco and NWP anticipate 2025 growth capital expenditures will be approximately $336 million and $43 million, respectively, primarily for expansion projects, and $423 million and $186 million, respectively, for maintenance projects.

They expect to fund these capital expenditures with cash from operations .

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:

Management’s Discussion and Analysis (Continued)

Cash and cash equivalents on hand

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Share repurchase program

As of December 31, 2024, Williams has approximately $24.7 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, or the commercial paper program, as well as proceeds from asset monetizations.

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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Cash and cash equivalents $ 63

Capacity available under Williams’ $3.75 billion credit facility, less amounts outstanding under Williams’ $3.5 billion commercial paper program (1)

Capacity available under Williams’ $3,750 million credit facility, less amounts outstanding under Williams’ $3,500 million commercial paper program (1)

(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 $455 million of Commercial paper (at par value) outstanding as of December 31, 2024.

Management’s Discussion and Analysis (Continued)

December 31, 2024, the highest amount outstanding under the commercial paper program and credit facility during 2024 was $730 million.

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.

Williams increased the regular quarterly cash dividend to common stockholders by approximately 6.1 percent from the $0.4475 per share paid in each quarter of 2023, to $0.4750 per share paid in each quarter of 2024.

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.

Management’s Discussion and Analysis (Continued)

Registrations

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Rating Agency Outlook Senior Unsecured

S&P Global Ratings Positive

Moody’s Investors Service Stable Baa2

S&P Global Ratings Stable

Moody’s Investors Service Positive

Fitch Ratings Positive

In January 2025, Fitch Ratings changed its Outlook from Stable to Positive.

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.

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Sources (Uses) of Cash

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

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:

Cash Flow Year Ended December 31,

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Financing 4,940 3,594 2,755

Proceeds from sale of business ( Note 3 )

Investing — 346 —

Proceeds from commercial paper – net Financing 245 — 372

Proceeds from dispositions of equity-method investments (Note 8)

Investing — 161 —

Proceeds from commercial paper – net

Financing — 372 345

Proceeds from sale of business ( Note 3 )

Investing — — 346

Uses of cash and cash equivalents:

Capital expenditures Investing (4,893) (2,573) (2,516)

Common dividends paid Financing (2,442) (2,316) (2,179)

Payments of long-term debt Financing (2,827) (2,946) (634)

Purchases of and contributions to equity-method investments Investing (511) (114) (141)

Dividends and distributions paid to noncontrolling interests Financing (259) (242) (213)

Purchases of businesses, net of cash acquired ( Note 3 )

Investing (1) (2,244) (1,568)

Common dividends paid Financing (2,316) (2,179) (2,071)

Capital expenditures Investing (2,573) (2,516) (2,253)

Dividends and distributions paid to noncontrolling interests Financing (242) (213) (204)

Payments of commercial paper – net

Financing — (269) —

Purchases of and contributions to equity-method investments Investing (114) (141) (166)

Purchases of treasury stock Financing — — (130)

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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 and amortization , Provision (benefit) for deferred income taxes , Equity (earnings) losses , Net unrealized (gain) loss from commodity derivative instruments , Gain on sale of business, 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 for the year ended December 31, 2024, decreased from the same period in 2023 primarily due to unfavorable changes in margin requirements, lower operating income (excluding non-cash items previously discussed), and unfavorable changes in net operating working capital.

Williams’ Net cash provided (used) by operating activities in 2023 increased from 2022 primarily due to higher operating income (excluding noncash items as previously discussed), as well as favorable changes in net operating working capital and margin requirements, partially offset by lower Distributions from equity-method investees .

Environmental

Williams is a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which it currently does not own (see Note 18 – Contingencies and Commitments).

Williams is monitoring these sites in a coordinated effort with other potentially responsible parties, the EPA, or other governmental authorities.

Williams is jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others.

Current estimates of the most likely costs of such activities are approximately $42 million, all of which are included in Other current liabilities

Management’s Discussion and Analysis (Continued)

and Regulatory liabilities, deferred income, and other at December 31, 2024.

Williams will seek to recover approximately $3 million of accrued costs related to remediation activities by its interstate gas pipelines through future natural gas transmission rates.

The remainder of these costs will be funded from operations.

During 2024, Williams paid approximately $11 million for cleanup and/or remediation and monitoring activities.

Williams expects to pay approximately $5 million in 2025 for these activities.

Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or Williams’ experience with other similar cleanup operations.

At December 31, 2024, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs.

Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

The EPA and various state regulatory agencies routinely propose and promulgate new rules and issue updated guidance to existing rules.

These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine maximum achievable control technology, reviews and updates to the National Ambient Air Quality Standards, and rules for new and existing source performance standards for volatile organic compounds and methane.

Williams continuously monitors these regulatory changes and how they may impact its operations.

Implementation of new or modified regulations may result in impacts to Williams’ operations and increase the cost of additions to Property, plant, and equipment – net for both new and existing facilities in affected areas;

however, due to regulatory uncertainty on final rule content and applicability timeframes, Williams is unable to reasonably estimate the cost these regulatory impacts at this time.

Williams considers prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates for its interstate natural gas transmission pipelines.

Historically, with limited exceptions, Williams has been permitted recovery of these environmental costs, and the intent is to continue seeking recovery of such costs through future rate filings.

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.

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

What changed 10-K

Item 7. Management’s Discussion and Analysis