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Item 7. Management’s Discussion and Analysis

2025-02-25 compared with 2024-02-21 · 568 added, 406 removed, 232 unchanged (81% of the section changed)

Management’s Discussion and Analysis of Financial Condition and Results of Operations

We are an energy company committed to being the leader in providing infrastructure that safely delivers natural gas products to reliably fuel the clean energy economy.

Our operations are located in the United States.

Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high-quality, low-cost transportation of natural gas to large and growing markets.

Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our 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.

The rates are established primarily through the FERC’s ratemaking process, but we also may negotiate rates with our customers pursuant to the terms of our tariffs and FERC policy.

Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs.

We focus on consistently attracting new business by providing highly reliable service to our customers.

These services include natural gas gathering, processing, treating, compression and storage, NGL fractionation, transportation and storage, crude oil production handling and transportation, as well as marketing services for NGL, crude oil, and natural gas.

Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented within the following reportable segments:

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

All remaining business activities, including our upstream operations and corporate activities, are included in Other.

Our reportable segments are comprised of the following business activities:

• Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco, Northwest Pipeline, and MountainWest, 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, including a 51 percent interest in Gulfstar One, a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery.

Transmission & Gulf of Mexico also includes natural gas storage facilities and pipelines providing services in north Texas.

• Northeast G&P is comprised of our 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 investment in Laurel Mountain, a 50 percent equity-method investment in Blue Racer, and Appalachia Midstream Investments.

• West is comprised of our 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 we acquired the remaining ownership interest in November 2023.

This segment also includes our NGL storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in OPPL, a 20 percent equity-method investment in Targa Train 7, and a 15 percent equity-method investment in Brazos Permian II.

• Gas & NGL Marketing Services is comprised of our 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 our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto included in Part II, Item 8 of this report.

In December 2023, we paid a regular quarterly dividend of $0.4475 per share.

On January 30, 2024, our board of directors approved a regular quarterly dividend of $0.4750 per share payable on March 25, 2024.

Overview of the Results of Operations

Combined Management’s Discussion and Analysis of Financial Condition and Results of Operations Page

Company Outlook

Critical Accounting Estimates

Results of Operations

Management ’ s Discussion and Analysis of Financial Condition and Liquidity

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

Its operations are located in the United States.

Williams’ interstate natural gas pipeline strategy is to create value by maximizing the utilization of its pipeline capacity by providing high-quality, low-cost transportation of natural gas to large and growing markets.

Williams’ gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC.

As such, Williams’ rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation.

The rates are established primarily through the FERC’s ratemaking process, but Williams may also negotiate rates with its customers pursuant to the terms of its tariffs and FERC policy.

Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of the cost of service is recovered through firm capacity reservation charges in transportation rates.

The ongoing strategy of Williams’ midstream operations is to safely and reliably operate large-scale midstream infrastructure where its assets can be fully utilized and drive low per-unit costs.

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

These services include natural gas gathering, 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.

In December 2024, Williams paid a regular quarterly dividend of $0.4750 per share.

On January 28, 2025, Williams’ board of directors approved a regular quarterly dividend of $0.5000 per share payable on March 31, 2025.

Overview of Year Ended December 31, 2024

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

for the year ended December 31, 2023, increased by $1.13 billion over the prior year.

Further discussion of our results is found in this report in the Results of Operations.

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

Further discussion of the results is found in this report in the Results of Operations.

Recent Developments

Transco FERC Rate Case Filing

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

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.

Expansion Project Updates

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Ongoing major expansion projects are discussed later in Company Outlook.

Northeast G&P

Susquehanna Supply Hub Gathering Expansion

We have an agreement in place with a third party for a construction project to facilitate natural gas production growth in the Susquehanna region.

We constructed approximately 22 miles of gathering pipeline and associated incremental compression.

The system added incremental natural gas gathering capacity of 320 MMcf/d.

Transmission & Gulf of America

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.

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.

Utica Shale Gathering Expansion

We have an agreement in place with a third party for a construction project to facilitate natural gas production growth in the Utica region on our Cardinal gathering system.

We constructed approximately 30 miles of gathering pipeline and associated incremental compression.

The system added incremental natural gas gathering capacity of 125 MMcf/d.

Phase 1 of this project was placed into service in the third quarter of 2023 and Phase 2 went into service in the fourth quarter of 2023.

Transmission & Gulf of Mexico

The project increased capacity by 423 Mdth/d.

Regional Energy Access

In January 2023, we 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.

We placed approximately half of the project into service in the fourth quarter of 2023 and plan to place the remainder of the project into service as early as the fourth quarter of 2024, assuming timely receipt of all necessary regulatory approvals.

The project is expected to increase capacity by 829 Mdth/d.

Acquisitions and Divestitures (see Note 3 – Acquisitions and Divestitures)

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, we closed on the acquisition of 100 percent of a strategic portfolio of natural gas storage facilities and pipelines, located in Louisiana and Mississippi, from Hartree Partners LP for $1.95 billion, subject to working capital and post-closing adjustments.

The purpose of this acquisition was to expand our natural gas storage footprint in the Gulf Coast region, and will be reported in the Transmission & Gulf of

Mexico segment.

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.

DJ Basin Acquisitions

On November 30, 2023, we closed on the acquisition of 100 percent of Cureton, whose operations are located in the DJ Basin, for $546 million, subject to working capital and post-closing adjustments.

Concurrently, we closed on the acquisition of an additional 50 percent interest in our equity-method investment RMM for $704 million.

We now own 100 percent of and consolidate RMM.

The purpose of these acquisitions was to expand our gathering and processing footprint in the DJ Basin.

The Cureton Acquisition was funded with cash on hand.

Substantially all of the RMM purchase price is not due to the seller until the first quarter of 2025, does not accrue interest until the fourth quarter of 2024, and may be repaid early without penalty.

These businesses are reported within the West segment.

Sale of Certain Gulf Coast Liquids Pipelines

On September 29, 2023, we completed the sale of various petrochemical and feedstock pipelines and associated contracts in the Gulf Coast region for $348 million.

As a result of this sale, we recorded a gain of $129 million in 2023 in our Transmission & Gulf of Mexico segment.

MountainWest Acquisition

On February 14, 2023, we closed on the acquisition of 100 percent of MountainWest Pipelines Holding Company which includes FERC-regulated interstate natural gas pipeline systems and natural gas storage capacity, for $1.08 billion of cash, funded with available sources of short-term liquidity, and retaining $430 million outstanding principal amount of MountainWest long-term debt.

The MountainWest Acquisition expands our existing transmission and storage infrastructure footprint into major markets in Utah, Wyoming, and Colorado.

This business is reported within the Transmission & Gulf of Mexico segment.

Favorable Judgment Against Energy Transfer

We have been involved in litigation since 2016 in Delaware Chancery Court with Energy Transfer Equity, L.P.

(Energy Transfer) related to the Agreement and Plan of Merger with Energy Transfer, dated as of September 28, 2015.

On December 29, 2021, the court entered judgment in our favor in the amount of $410 million, plus interest at the contractual rate, and our reasonable attorneys’ fees and expenses.

On September 21, 2022, the Delaware Chancery Court entered a final order and judgment awarding us a termination fee, attorney’s fees, expenses, and interest in the amount of $602 million plus additional interest starting September 17, 2022.

Energy Transfer appealed to the Delaware Supreme Court.

The Delaware Supreme Court held oral argument en banc on July 12, 2023.

On October 10, 2023, the Delaware Supreme Court issued an opinion affirming the Delaware Chancery Court ruling.

On October 25, 2023, Energy Transfer filed a motion for reargument with the Delaware Supreme Court, which was denied.

On November 28, 2023, we received a $627 million payment from Energy Transfer for the final order and judgment.

On the same day, we paid attorney fees which had been incurred on a contingent fee basis.

This resulted in a net gain of $534 million reported as Net gain from Energy Transfer litigation judgment in our Consolidated Statement of Income for the year ended December 31, 2023 (See Note 17 – Contingencies and Commitments).

Northwest Pipeline FERC Rate Case Settlement

On November 15, 2022, Northwest Pipeline received approval from the FERC for a stipulation and settlement agreement which generally reduces rates effective January 1, 2023, resolves other rate issues, establishes a Modernization and Emission Reduction Program, and satisfies its rate case filing obligation.

Provisions were included in the settlement that establish a moratorium on any proceedings that would seek to place new rates in effect any earlier than January 1, 2026, and that a general rate case filing will be made for rates to become effective not later than April 1, 2028, unless we have entered into a pre-filing settlement prior to that date.

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).

Company Outlook

Our strategy is to provide a large-scale, reliable, and clean energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States.

We accomplish this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins.

We continue to maintain a strong commitment to safety, environmental stewardship including seeking opportunities for renewable energy ventures, operational excellence, and customer satisfaction.

We believe that accomplishing these goals will position us to deliver safe, reliable, clean energy services to our customers and an attractive return to our shareholders.

Our business plan for 2024 includes a continued focus on earnings and cash flow growth.

In 2024, our operating results are expected to benefit from the recent Gulf Coast Storage and DJ Basin acquisitions.

We also anticipate increases resulting from Transmission & Gulf of Mexico expansion projects, including the Regional Energy Access project, and annual inflation-based rate increases across our gathering and processing business.

These increases are partially offset by lower expected Gas & NGL Marketing Services results, the absence of realized hedge gains captured in 2023, and a decrease in expected volumes in the Appalachian Basin associated with a lower expected commodity price environment.

We seek 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.

Our growth capital and investment expenditures in 2024 are expected to be in a range from $1.45 billion to $1.75 billion, excluding acquisitions.

Growth capital spending in 2024 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting growth in the Haynesville Basin, and projects supporting the Northeast G&P business.

We also expect to invest capital in our Other segment ventures.

In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that reduce emissions, and meet legal, regulatory, and/or contractual commitments.

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

Williams’ strategy is to provide a large-scale, reliable, and clean energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States.

Williams accomplishes this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins.

Williams continues to maintain a strong commitment to safety, environmental stewardship including seeking opportunities for renewable energy ventures, operational excellence, and customer satisfaction.

Williams believes that accomplishing these goals will position us to deliver safe, reliable, clean energy services to its customers and an attractive return to shareholders.

Williams’ business plan for 2025 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.

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.

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)

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

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

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

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

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

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

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

Risk Factors in this report.

Risk Factors.

Expansion Projects

Our ongoing major expansion projects include the following:

Transmission & Gulf of Mexico

Williams’ ongoing major expansion projects include the following:

Transmission & Gulf of America

Deepwater Shenandoah Project

In June 2021, we 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 our existing Gulf of Mexico offshore infrastructure via a 5-mile 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.

We plan to place the project into service in the fourth quarter of 2024.

Deepwater Whale Project

In August 2021, we 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 our existing Western Gulf of Mexico offshore infrastructure via a 26-mile gas lateral pipeline from the Whale platform to the existing Perdido gas pipeline and adds a new 125-mile oil pipeline from the Whale platform to our existing junction platform.

We plan to place the project into service in the fourth quarter of 2024.

Regional Energy Access

The project is expected to increase capacity by 829 Mdth/d.

Southside Reliability Enhancement

In July 2023, we 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.

We plan to place the project into service as early as the fourth quarter of 2024, assuming timely receipt of all necessary regulatory approvals.

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

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 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

In January 2024, we 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.

We plan to place the project into service as early as the first quarter of 2025, assuming timely receipt of all necessary regulatory approvals.

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 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

In November 2023, we received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Mississippi and Alabama to a delivery point in Alabama.

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

In November 2023, Transco received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Mississippi and Alabama to a delivery point in Alabama.

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

The project is expected to increase capacity by 150 Mdth/d.

Commonwealth Energy Connector

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

Transco 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 105 Mdth/d.

Alabama Georgia Connector

In April 2023, we filed an 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 our Station 85 pooling point in Alabama to customers in Georgia.

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

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 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 64 Mdth/d.

Southeast Supply Enhancement

We plan to file an application with the FERC as early as the third quarter of 2024 for this 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 Virginia, North Carolina, South Carolina, Georgia, and Alabama.

We plan to place the project into service as early as the fourth quarter of 2027, assuming timely receipt of all necessary regulatory approvals.

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.

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 1,597 Mdth/d.

Overthrust Westbound Compression Expansion

In November 2023, we filed an application with 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.

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

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.

The project is expected to increase capacity by 115 Mdth/d.

Northeast G&P

Cardinal Gathering Expansion

We have an agreement in place with a third party to facilitate natural gas production growth in the Utica Shale region.

We plan to construct approximately 8 miles of gathering pipeline and associated incremental compression.

The system, once constructed, will add incremental capacity of 125 MMcf/d and will provide natural gas gathering services to the third party.

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

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.

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.

The project is expected to increase capacity by 80 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.

The project is expected to increase capacity by 98 Mdth/d.

Kelso-Beaver Reliability 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 June 2022, we announced our intention to construct 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 second half of 2025.

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, we announced our agreement with a third party to facilitate natural gas production growth in the Haynesville basin.

We plan to construct a greenfield gathering system in support of the third party’s 26,000-acre dedication.

The system, once constructed, will provide natural gas gathering services to the

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

This project is expected to go into service in the second half of 2025.

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.

Critical Accounting Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions.

We believe that 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 our financial condition or results of operations.

Pension and Postretirement Obligations

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

Preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions.

The nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on the financial condition or results of operations.

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.

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Expected long-term rate of return on plan assets

Our 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 our third-party independent investment advisor, as well as the investment strategy and relative weightings of the asset classes within the investment portfolio.

Our expected long-term rate of return on plan assets used for our pension plans was 5.17 percent in 2023.

The 2023 actual return on plan assets for our pension plans was approximately 11.4 percent.

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

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.

1 unchanged sentence

Treasury securities rate.

Regulatory Accounting

Transco and NWP are regulated by the FERC.

Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” (ASC 980) provides that certain costs that would otherwise be charged to expense should be deferred as regulatory assets, based on the expected recovery from customers in future rates.

Likewise, certain actual or anticipated credits that would otherwise reduce expense should be deferred as regulatory liabilities, based on the expected return to customers in future rates.

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

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.

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.

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.

A summary of regulatory assets and liabilities is included in Note 10 – Regulatory Assets and Liabilities.

Management’s Discussion and Analysis (Continued)

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2023 and should be read in conjunction with the results of operations by segment, as discussed in further detail following this consolidated overview discussion.

Williams’ Consolidated Overview

The following table and discussion is a summary of Williams’ consolidated results of operations for the three years ended December 31, 2024, and should be read in conjunction with the results of operations by segment, as discussed in further detail following this consolidated overview discussion.

Year Ended December 31,

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2023 $ Change

(Dollars in millions)

Service revenues $ 7,628 +602 +9 % $ 7,026 +490 +7 % $ 6,536

$ 7,026 +490 +7 % $ 6,536 +535 +9 % $ 6,001

Service revenues – commodity consideration

146 -114 -44 % 260 +22 +9 % 238

Product sales

2,779 -1,777 -39 % 4,556 +20 — % 4,536

Net gain (loss) from commodity derivatives

956 +1,343 NM (387) -239 -161 % (148)

Product sales and service revenues – commodity consideration 3,125 +200 +7 % 2,925 -1,891 -39 % 4,816

Net gain (loss) from commodity derivatives (250) -1,206 NM 956 +1,343 NM (387)

Total revenues 10,503 10,907 10,965

10,907 10,965 10,627

Costs and expenses:

Product costs

1,884 +1,485 +44 % 3,369 +562 +14 % 3,931

Net processing commodity expenses 151 -63 -72 % 88 +13 +13 % 101

Product costs and net processing commodity expenses 2,118 -83 -4 % 2,035 +1,422 +41 % 3,457

Operating and maintenance expenses 2,179 -195 -10 % 1,984 -167 -9 % 1,817

1,984 -167 -9 % 1,817 -269 -17 % 1,548

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

2,071 -62 -3 % 2,009 -167 -9 % 1,842

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

665 -29 -5 % 636 -78 -14 % 558

Gain on sale of business

(129) +129 NM — — — % —

Other (income) expense – net

(30) +58 NM 28 -12 -75 % 16

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

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

Total costs and expenses 7,164 6,596 7,947

6,596 7,947 7,996

Operating income (loss) 3,339 4,311 3,018

Equity earnings (losses) 560 -29 -5 % 589 -48 -8 % 637

Other investing income (loss) – net 108 +92 NM 16 +9 +129 % 7

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

Interest expense (1,364) -128 -10 % (1,236) -89 -8 % (1,147)

Net gain from Energy Transfer litigation judgment

534 +534 NM — — — % —

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

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

Income (loss) before income taxes

2,986 4,405 2,542

Provision (benefit) for income taxes

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

Income (loss) from continuing operations 2,346 3,400 2,117

1 unchanged sentence

Net income (loss) 2,346 3,303 2,117

3,303 2,117 1,562

Net income (loss) attributable to noncontrolling interests

124 -56 -82 % 68 -23 -51 % 45

Net income attributable to noncontrolling interests 121 +3 +2 % 124 -56 -82 % 68

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

3 unchanged sentences

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

Management’s Discussion and Analysis (Continued)

Service revenues increased primarily due to:

• Higher volumes from acquisitions at our Transmission & Gulf of Mexico segment;

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

• 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.

The net sum of Product sales and service revenues – commodity consideration , Product costs and net processing commodity expenses, and net realized gains and losses on commodity derivatives related to sales of product and shrink gas purchases for processing plants for the reportable segments comprise Commodity Margins .

Service revenues - commodity consideration represent payments received in the form of commodities for processing services provided.

Most of these commodity volumes are sold during the month processed and are offset within Product costs and net processing commodity expenses .

The sum of Product sales and net realized gains and losses on commodity derivatives related to the upstream operations comprise Net realized product sales .

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

• Higher 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.

Net natural gas marketing sales were impacted by higher storage costs;

partially offset by

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

The net sum of Service revenues – commodity consideration , Product sales , Product costs, net realized gains and losses on commodity derivatives related to sales of product, and net realized processing commodity expenses for our reportable segments (excludes Other) comprise our Commodity margins .

Product sales and net realized gains and losses on commodity derivatives at our Other segment, which reflect sales related to our upstream operations, comprise Net realized product sale s.

Service revenues – commodity consideration, which represent payments we receive in the form of commodities for processing services provided, decreased primarily due to lower NGL prices.

Most of these NGL volumes are sold during the month processed and are offset within Product costs below.

The Product sales decrease primarily consists of:

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

• Lower sales from upstream operations within Other;

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

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

As we are acting as agent for natural gas marketing customers, our natural gas marketing product sales are presented net of the related costs of those activities within our 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 our Gas & NGL Marketing Services, West, and Other segments (see Note 16 – Commodity Derivatives).

We experience 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 portfolio as well as upstream-related production.

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 contracts, which is not recognized until the underlying transaction occurs.

The Product costs decrease primarily consists of:

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

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

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

Net processing commodity expenses increased primarily due to:

• Unfavorable change in unrealized gains and losses from commodity derivatives related to processing plant shrink gas purchases (see Note 16 – Commodity Derivatives);

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

• Lower system management gas sales primarily at the Transmission & Gulf of America 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);

• 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.

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 and West segments, and 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 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 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;

partially offset by lower marketing activities primarily related to NGLs at the Gas & NGL Marketing Services segment;

partially offset by

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

Operating and maintenance expenses increased primarily due to operating costs of the assets acquired at the West and Transmission & Gulf of America 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.

The increase is partially offset by lower amortization of intangibles related to the acquisition of Sequent Energy Management, L.P.

and Sequent Energy Canada, Corp.

(Sequent) in 2021.

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 our 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 our 2021 Sequent Acquisition.

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.

Gain on sale of business resulted from our sale of certain liquids pipelines in the Gulf Coast region (see Note 3 – Acquisitions and Divestitures).

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 Northwest Pipeline and the absence of 2022 regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate;

• 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 our share of a loss contingency accrual related to our 14 percent ownership in Aux Sable Liquid Products LP, 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 our existing equity-method investment in RMM to fair value with the acquisition of the remaining 50 percent ownership (see Note 3 – Acquisitions and Divestitures).

The increase in Interest expense was primarily due to our 2023 debt issuances and MountainWest's long-term debt (see Note 12 – Debt and Banking Arrangements), partially offset by an increase in interest capitalized related to ongoing expansion projects.

The Net gain from Energy Transfer litigation judgment resulted from a favorable ruling on the final order and judgment of our complaint against Energy Transfer (see Note 17 – Contingencies and Commitments).

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 our Transmission & Gulf of Mexico segment and the related effects of deferred taxes within Other.

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 our estimate of the state deferred income tax rate in both periods, and the absence of 2022 federal income tax settlements.

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.

Income (loss) from discontinued operations in 2023 includes a pre-tax charge of $125 million to increase the related accrued liability associated with our Alaska refinery contamination litigation, partially offset by the related income tax effect (see Note 17 – Contingencies and Commitments).

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.

Service revenues increased primarily due to higher gathering and processing rates driven by favorable commodity prices and annual contractual rate escalations for certain of our West and Northeast G&P operations, higher volumes including from the Trace Acquisition and NorTex Asset Purchase, higher transportation fee revenues associated with the Leidy South expansion project placed fully in service at Transco in December 2021, and higher reimbursable electric power costs and storage rates which are substantially offset in Operating and maintenance expenses .

Service revenues – commodity consideration increased primarily due to higher NGL prices, partially offset by lower NGL volumes.

These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided.

Most of these NGL volumes are sold during the month processed and therefore are offset within Product costs below.

Product sales increased primarily due to higher marketing sales prices and volumes, including increased volumes associated with the Sequent Acquisition in third-quarter 2021 and the Trace Acquisition in second-quarter 2022.

Product sales also increased due to higher sales volumes and prices associated with our upstream operations and system management gas sales, as well as higher prices and lower volumes related to our equity NGL sales activities.

These increases were partially offset by an unfavorable change in natural gas marketing sales primarily due to the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).

As we are acting as agent for natural gas marketing customers of our Gas & NGL Marketing Services segment, our natural gas marketing product sales are presented net of the related costs of those activities, including significant 2022 lower of cost or net realizable value adjustments to our natural gas inventory.

The unfavorable change in Net gain (loss) from commodity derivatives primarily reflects higher net unrealized losses in our Gas & NGL Marketing Services segment, and higher net realized losses related to derivative contracts in our Other segment.

Lower net realized losses at our West segment and a net unrealized gain at our Other segment in 2022 partially offset these impacts.

Product costs decreased primarily due to the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs.

This decrease was partially offset by higher prices and volumes associated with our NGL marketing activities, including the increase in volumes associated with the Trace Acquisition in second-quarter 2022, as well as significant 2022 lower of cost or net realizable value adjustments to our NGL inventory.

Product costs also increased due to higher system management gas purchases and higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities.

Net processing commodity expenses decreased primarily due to the impact of a 2022 net unrealized gain from derivatives for processing plant shrink gas purchases and lower volumes for natural gas purchases associated with our equity NGL production activities, partially offset by higher net realized prices.

Operating and maintenance expenses increased primarily due to higher operating and maintenance costs, including $63 million of higher reimbursable electric power and storage costs which are substantially offset in Service revenues.

The increase was also a result of higher expenses associated with our upstream operations, increased costs associated with Transco's Leidy South expansion project placed in service in December 2021, higher employee-related expenses, and higher expenses associated with the 2022 Trace Acquisition and NorTex Asset Purchase.

Depreciation and amortization expenses increased primarily due to amortization of intangibles acquired in the Sequent and Trace Acquisitions and an increase in depreciation at Transco related to ARO revisions (offset in Other (income) expense – net within Operating income (loss) resulting in no net impact on our results of operations), partially offset by the absence of 2021 depreciation on certain decommissioned facilities in our West segment.

Selling, general, and administrative expenses increased primarily due to higher employee-related expenses driven by the Sequent Acquisition in July 2021 and higher expenses for various corporate costs, including technology costs to support efforts to track and quantify emissions associated with natural gas procurement, transmission, and delivery.

Other (income) expense – net within Operating income (loss) changed unfavorably primarily due to charges related to Eminence storage cavern abandonments and monitoring, as well as regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate, offset by the deferral of ARO depreciation (offset in Depreciation and amortization expenses resulting in no net impact on our results of operations).

Equity earnings (losses) changed favorably primarily due to increases at investments across our West segment, including RMM, and at Laurel Mountain, partially offset by a decrease at Appalachia Midstream Investments.

Provision (benefit) for income taxes changed favorably primarily due to a benefit associated with a decrease in our estimate of the state deferred income tax rate, a benefit related to the release of a valuation allowance, and federal settlements, partially offset by higher pre-tax income.

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.

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

Year-Over-Year Operating Results – Segments

We evaluate segment operating performance based upon Modified EBITDA .

Note 18 – Segment Disclosures includes a reconciliation of this non-GAAP measure to Net income (loss) .

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 .

Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance.

In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets.

In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of Williams’ assets.

Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.

Transmission & Gulf of Mexico

Management’s Discussion and Analysis (Continued)

Transmission & Gulf of America

Year Ended December 31,

1 unchanged sentence

Service revenues $ 4,246 $ 3,858 $ 3,579

Service revenues – commodity consideration (1) 38 64 52

Product sales (1) 252 404 349

Product sales and service revenues – commodity consideration (1) 382 290 468

Net realized gain (loss) from commodity derivatives (1) — 2 —

Segment revenues 4,628 4,150 4,047

Product costs (1) (246) (399) (349)

Net processing commodity expenses (1) (13) (26) (17)

Product costs and net processing commodity expenses (1) (329) (259) (425)

Other segment costs and expenses (1,199) (1,157) (1,141)

1 unchanged sentence

Proportional Modified EBITDA of equity-method investments 173 205 193

Transmission & Gulf of Mexico Modified EBITDA $ 3,068 $ 2,674 $ 2,621

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

Commodity margins $ 53 $ 33 $ 43

1 unchanged sentence

(1) Included as a component of Commodity margins .

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

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.

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

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

partially offset by

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

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

Other segment costs and expenses increased primarily due to:

• Higher operating expenses and administrative costs including higher operating, acquisition and transition costs related to Williams’ Gulf Coast Storage and Discovery Acquisitions, as previously discussed;

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;

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

partially offset by

• Lower project feasibility costs;

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

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

6 unchanged sentences

• 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 (see Note 3 – Acquisitions and Divestitures).

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

• 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 our MountainWest Acquisition and NorTex Asset Purchase;

• 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 ;

5 unchanged sentences

• 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 (see Note 3 – Acquisitions and Divestitures).

Transmission & Gulf of Mexico 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 $163 million increase in Transco’s service revenues primarily associated with the Leidy South expansion project placed fully in service in December 2021, park and loan services, short-term firm transportation, overall demand, and commodity fee revenues.

Additionally, 2022 benefited from higher reimbursable electric power costs and storage rates effective since the second quarter of 2022, partially offset by lower cash out surcharges, all of which are offset by similar changes in electricity, storage and cash out charges reflected in Other segment costs and expenses;

• A $21 million increase in the Eastern Gulf Coast region primarily due to higher production handling and gathering volumes from the absence of temporary shut-ins due to producer operational issues and weather-related events in 2021, partially offset by a decrease at Gulfstar One for the Tubular Bells field primarily due to lower production handling, gathering and transportation volumes from natural decline;

• A $16 million increase primarily related to storage and transportation revenues due to the acquisition of NorTex in August 2022;

partially offset by

• A $13 million decrease in the Western Gulf Coast region primarily at Perdido due to lower transportation and gathering volumes from temporary downtime from producer operational issues in 2022.

Commodity margins associated with our equity NGLs increased $5 million primarily driven by favorable NGL sales prices, partially offset by higher prices for natural gas purchases associated with our equity NGL production activities.

Other segment costs and expenses increased primarily due to higher operating costs including higher reimbursable electric power costs and storage costs, partially offset by favorable cash out charges, all of which are offset by similar changes in electricity reimbursements, cash out charges, and storage revenues reflected in Service revenues.

Additionally, 2022 was impacted by higher costs associated with the Leidy South expansion project;

maintenance costs primarily related to general maintenance at Transco, Gulf Coast region, and Northwest Pipeline;

charges related to Eminence storage cavern abandonments and monitoring;

and regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate, higher employee-related costs, corporate allocations, and operations acquired in the NorTex Asset Purchase.

These increases are partially offset by a favorable change in the deferral of ARO related depreciation at Transco.

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.

Northeast G&P

2 unchanged sentences

Service revenues $ 1,913 $ 1,896 $ 1,654

Service revenues – commodity consideration (1) 5 14 7

Product sales (1) 132 134 99

Product sales and service revenues – commodity consideration (1) 112 137 148

Segment revenues 2,025 2,033 1,802

Product costs (1) (123) (135) (99)

Net processing commodity expenses (1) (2) (3) (2)

Product costs and net processing commodity expenses (1) (88) (125) (138)

Other segment costs and expenses (581) (566) (522)

3 unchanged sentences

(1) Included as a component of Commodity margins .

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

Service revenues increased primarily due to:

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

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);

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

partially offset by

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

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

Commodity margins increased due to a restructured gas purchase deal in 2024 which allowed for margin gain on residue pricing and liquids from fixed recoveries.

In addition, Williams was not significantly impacted by system constraints which impacted margins in 2023.

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

The increase was partially offset by lower maintenance expenses and the absence of the 2023 loss contingency accrual.

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

Additionally, Appalachia 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 .

4 unchanged sentences

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 our $31 million share of a loss contingency accrual related to our 14 percent ownership.

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 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.

Service revenues increased primarily due to:

• A $64 million increase in revenues at the Northeast JV primarily related to higher gathering, processing, and fractionation volumes as well as higher processing rates;

• A $43 million increase in revenues in the Utica Shale region primarily related to higher gathering rates resulting from annual cost of service contract redeterminations, as well as proceeds from the release of an acreage dedication;

• A $14 million increase in revenues associated with reimbursable expenses, which is offset by similar changes in the charges reflected in Other segment costs and expenses;

• No change in revenues at Susquehanna Supply Hub primarily related to higher gathering rates, offset by lower gathering volumes.

Other segment costs and expenses increased primarily due to higher operating expenses, including higher electricity and fuel, which is partially offset in Service revenues .

Proportional Modified EBITDA of equity-method investments decreased at Appalachia Midstream Investments primarily driven by lower gathering rates resulting from annual cost of service contract redeterminations as well as lower volumes.

Additionally, there was a decrease at Blue Racer primarily due to lower volumes.

The decrease was partially offset by an increase at Laurel Mountain primarily due to higher commodity-based gathering rates.

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

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.

Year Ended December 31,

1 unchanged sentence

Service revenues $ 1,718 $ 1,502 $ 1,542

Service revenues – commodity consideration (1)

Product sales (1) 441 841 643

Product sales and service revenues – commodity consideration (1) 947 544 1,023

Net realized gain (loss) from commodity derivatives relating to service revenues 10 82 (1)

2 unchanged sentences

Segment revenues 2,669 2,135 2,561

Product costs (1) (425) (813) (608)

Net processing commodity expenses (1) (92) (105) (85)

Product costs and net processing commodity expenses (1) (844) (517) (918)

Other segment costs and expenses (645) (542) (564)

4 unchanged sentences

(1) Included as a component of Commodity margins .

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

Service revenues increased primarily due to:

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

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

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

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

partially offset by

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

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

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.

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

Commodity margins increased $63 million primarily due to $39 million higher margins associated with the DJ Basin Acquisitions, as previously discussed.

Margins also increased $21 million from Williams’ equity NGLs primarily due to lower net realized prices for natural gas purchases and lower volumes of natural gas purchased both associated with equity NGL production activities;

partially offset by lower volumes of equity NGL sold and lower net realized NGL sales prices.

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

partially offset by higher system gains and the absence of a fourth quarter 2023 write-down of assets held for sale.

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

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.

5 unchanged sentences

• 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 (see Note 3 – Acquisitions and Divestitures);

• 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 our natural gas hedge positions.

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

Other segment costs and expenses decreased primarily due to a favorable change in our 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.

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 as of November 30, 2023.

West Modified EBITDA increased primarily due to higher Service revenues and a favorable change in Net realized gain (loss) from commodity derivatives, partially offset by higher Other segment costs and expenses.

Service revenues increased primarily due to:

• A $186 million increase in the Haynesville Shale region primarily due to higher gathering volumes including volumes from the Trace Acquisition as well as higher gathering rates driven by favorable commodity pricing;

• A $96 million increase in the Barnett Shale region primarily due to higher gathering rates driven by favorable commodity pricing;

• A $14 million increase associated with higher fractionation fees primarily due to higher fractionation volumes from a new contract;

• A $4 million increase in the Eagle Ford Shale region primarily due to higher MVC revenues, escalated gathering rates, and higher deferred revenue amortization, substantially offset by lower volumes due to decreased producer activity;

partially offset by

• A $10 million decrease in the Wamsutter region primarily due to lower MVC revenue.

Net realized gain (loss) from commodity derivatives relating to service revenues changed favorably due to a change in settled commodity prices relative to our hedge positions.

Product margins from our equity NGLs increased $6 million primarily due to higher net realized NGL sales prices, partially offset by higher net realized prices for natural gas purchases associated with our equity NGL production activities.

Additionally, volumes of equity NGL sold and natural gas purchased associated with our equity NGL production activities were lower primarily due to a customer contract change.

Margins from other sales activities increased $16 million primarily due to higher condensate sales and favorable pricing.

Marketing margins decreased $20 million primarily due to the absence of the favorable impact of Winter Storm Uri in the first quarter of 2021.

Other segment costs and expenses increased primarily due to higher operating expenses related to timing and scope of activities including from operations acquired in the Trace Acquisition, the absence of gains on asset sales in

2021, higher corporate allocations, acquisition-related costs associated with the Trace Acquisition, and an unfavorable change in our net imbalance liability due to changes in pricing.

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

Gas & NGL Marketing Services

5 unchanged sentences

Net unrealized gain (loss) from commodity derivative instruments (335) 702 (321)

702 (321) (109)

Net gain (loss) from commodity derivatives (263) 817 (304)

817 (304) (84)

Segment revenues 1,789 2,878 3,233

Net unrealized gain (loss) from commodity derivative instruments within Net processing commodity expenses

Product costs (1) (1,799) (1,786) (3,228)

Net unrealized gain (loss) from commodity derivative instruments within Net processing commodity expenses

Other segment costs and expenses (108) (99) (92)

3 unchanged sentences

(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 .

Commodity margins decreased $64 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.

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 our 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;

• 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 our 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 our 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 relates to derivative contracts that are not designated as hedges for accounting purposes.

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

Gas & NGL Marketing Services Modified EBITDA decreased primarily due to higher net unrealized loss from derivative instruments and higher Other segment costs and expenses , partially offset by higher Commodity margins .

Commodity margins increased $158 million primarily due to:

• A $188 million increase in natural gas marketing margins which included the following:

◦ A $301 million increase in natural gas transportation capacity marketing margins primarily resulting from the Sequent Acquisition in the third quarter of 2021 and an increase in favorable pricing spreads in 2022 compared to 2021;

partially offset by

◦ A $58 million decrease associated with our legacy natural gas marketing operations primarily due to the absence of the favorable impact of Winter Storm Uri in the first quarter of 2021;

◦ A $55 million decrease in natural gas storage marketing margins due primarily to an increase in lower of cost or net realizable value inventory adjustments of $115 million and higher storage fees, partially offset by higher storage withdrawals in 2022 compared to 2021.

• A $30 million decrease in our NGL marketing margins primarily due to lower of cost or net realizable value inventory adjustments in 2022.

Net unrealized gain (loss) from commodity derivative instruments changed primarily due to the Sequent Acquisition in July 2021, and a change in forward commodity prices relative to our hedge positions in 2022 compared to 2021.

Other segment costs and expenses increased primarily due to higher employee-related costs related to the Sequent Acquisition and higher corporate allocations.

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.

Year Ended December 31,

2 unchanged sentences

Product sales (1) 420 442 706

Net realized gain (loss) from commodity derivative instruments (1)

47 (104) (20)

Net unrealized gain (loss) from commodity derivative instruments

Net realized gain (loss) from derivative instruments (1) 35 47 (104)

Net unrealized gain (loss) from derivative instruments (26) 1 25

Net gain (loss) from commodity derivatives 9 48 (79)

Segment revenues 506 651 345

Other segment costs and expenses (197) (217) (167)

Net revenues from upstream operations, corporate, and other business activities.

Other costs and expenses

(209) (197) (217)

Net gain from Energy Transfer litigation judgment — 534 —

Proportional Modified EBITDA of equity-method investments 2 (2) —

Other Modified EBITDA $ 841 $ 434 $ 178

Modified EBITDA from upstream operations, corporate, and other business activities

$ 237 $ 841 $ 434

Net realized product sales $ 455 $ 489 $ 602

1 unchanged sentence

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

Other Modified EBITDA increased primarily due to the Net gain from Energy Transfer litigation judgmen t (see Note 17 – Contingencies and Commitments), partially offset by lower results from our upstream operations, which included the following:

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

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

partially offset by

• An increase in Other segment costs and expenses associated with our 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 our Wamsutter region.

Other segment costs and expenses not associated with our 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.

Other Modified EBITDA increased primarily due to $248 million higher results from our upstream operations which included the following:

• A $289 million increase in Net realized product sales primarily due to higher commodity prices in 2022, partially offset by the absence of the favorable impact of Winter Storm Uri in 2021 and an unfavorable change in Net realized gain (loss) from commodity derivative instruments due to an increase in commodity prices relative to our hedge positions and an increase in the volume of production hedged in 2022 compared to 2021.

Net realized product sales also increased due to higher production from new wells and higher volumes associated with acquisitions of additional ownership interests in 2021;

• A $25 million favorable change in Net unrealized gain (loss) from commodity derivative instruments due to a change in forward commodity prices relative to our hedge positions and an increase in the volume of production hedged in 2022 compared to 2021;

Management’s Discussion and Analysis (Continued)

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

• A $34 million decrease in Net realized product sales from upstream operations primarily due to lower volumes and lower net realized commodity prices associated with Williams’ South Mansfield production in the Haynesville Shale region, and lower net realized commodity prices associated with Williams’ Wamsutter region.

These decreases were partially offset by higher production volumes associated with Williams’ Wamsutter region production, including from the Crowheart Acquisition in the fourth quarter of 2024.

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

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

• 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

• A $66 million increase in Other segment costs and expenses primarily due to the increased scale of our upstream operations and higher associated production taxes, which were also impacted by higher commodity prices and higher volumes as well as higher tax rates.

Other segment costs and expenses also includes an $11 million charge related to an accrual for loss contingency in 2022, substantially offset by the absence of a $10 million charge related to an accrual for loss contingency in 2021.

• 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.

Management’s Discussion and Analysis (Continued)

Year Ended December 31,

2024 $ Change

Natural gas transportation service revenues $ 2,619 +113 +5 % $ 2,506

Natural gas storage service revenues 200 +14 +8 % 186

Natural gas product sales 118 -19 -14 % 137

Other service revenues 27 -10 -27 % 37

Total revenues 2,964 2,866

Costs and expenses:

Natural gas product costs 118 +19 +14 % 137

Operating and maintenance expenses 510 +7 +1 % 517

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

Depreciation and amortization expenses 545 -26 -5 % 519

Taxes, other than income taxes 111 -6 -6 % 105

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

Total costs and expenses 1,465 1,455

Operating income (loss) 1,499 +88 +6 % 1,411

Interest expense (324) — — % (324)

Interest income 58 -29 -33 % 87

Allowance for equity and borrowed funds used during construction (AFUDC) 88 +11 +14 % 77

Other income (expense) – net (8) -4 -100 % (4)

Net income (loss) $ 1,313 +66 +5 % $ 1,247

* + = Favorable change;

- = Unfavorable change;

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

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

Transco has cash out sales, which settle gas imbalances with shippers.

In the course of providing transportation services to customers, Transco may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers.

Additionally, Transco transports gas on various pipeline systems, which may deliver different quantities of gas on Transco’s behalf than the quantities of gas received from Transco.

These transactions

Management’s Discussion and Analysis (Continued)

result in gas transportation and exchange imbalance receivables and payables.

Transco’s tariff includes a method whereby the majority of transportation imbalances are settled on a monthly basis through cash out sales or purchases.

The cash out sales have no impact on Transco’s operating income.

Revenues increased primarily due to:

• 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.

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.

Management’s Discussion and Analysis (Continued)

Year Ended December 31,

2024 $ Change

Natural gas transportation service revenues $ 416 $ +1 — % $ 415

Natural gas storage service revenues 15 — — % 15

Other service revenues 13 +3 +30 % 10

Total revenues 444 440

Costs and expenses:

Operating and maintenance expenses 95 -7 -8 % 88

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

Depreciation and amortization expenses 111 — — % 111

Taxes, other than income taxes 14 -2 -17 % 12

Other (income) expense - net (18) +2 +13 % (16)

Total costs and expenses 253 246

Operating income (loss) 191 -3 -2 % 194

Interest expense (28) — — % (28)

Allowance for equity and borrowed funds used during construction (AFUDC) 10 +6 +150 % 4

Other income (expense) – net 7 -3 -30 % 10

Net income (loss) $ 180 $ — — % $ 180

* + = Favorable change;

- = Unfavorable change;

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

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.

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.

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.

Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity

We have continued to focus on earnings and cash flow growth, noting significant increases in both net income and cash provided by operating activities.

During 2023, investing and financing expenditures included $2.5 billion of capital expenditures, $1.6 billion of acquisitions including MountainWest and Cureton, and $2.2 billion of dividends paid to common shareholders.

These expenditures were funded in part by $5.9 billion of cash provided by operating activities (which includes a net $534 million related to our favorable Energy Transfer litigation outcome - see Note 17 – Contingencies and Commitments), and cash from borrowing activities of $2.5 billion.

Our financial position also reflects the deferred consideration obligation for the RMM Acquisition (see Note 3 – Acquisitions and Divestitures).

We ended the year with $2.150 billion of Cash and cash equivalents as reported on our Consolidated Balance Sheet.

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.

Williams ended the year with $60 million of Cash and cash equivalents .

See also the following section titled Sources (Uses) of Cash .

Our growth capital and investment expenditures in 2024 are currently expected to be in a range from $1.45 billion to $1.75 billion, excluding the Gulf Coast Storage Acquisition for $1.95 billion (see Note 3 – Acquisitions and Divestitures).

We also expect to invest capital in our Other segment ventures.

We intend to fund substantially all planned 2024 capital spending with cash available after paying dividends.

We retain 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 our common stock.

On January 5, 2024, we issued $2.1 billion in long-term debt (see Note 12 – Debt and Banking Arrangements).

As of December 31, 2023, we have approximately $2.337 billion of long-term debt due within one year.

Our potential sources of liquidity available to address these maturities include cash on hand, proceeds from refinancing, our credit facility, or our commercial paper program, as well as proceeds from asset monetizations.

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2024.

Our potential material internal and external sources and uses of liquidity are as follows:

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.

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 2025 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:

Cash and cash equivalents on hand

Cash generated from operations

Distributions from our equity-method investees

Utilization of our credit facility and/or commercial paper program

Distributions from equity-method investees

Utilization of the credit facility and/or commercial paper program

Cash proceeds from issuance of debt and/or equity securities

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Other operating costs including human capital expenses

Quarterly dividends to our shareholders

Repayments of borrowings under our credit facility and/or commercial paper program

Quarterly dividends to shareholders

Repayments of borrowings under the credit facility and/or commercial paper program

Debt service payments, including payments of long-term debt

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Share repurchase program

At December 31, 2023, we have approximately $23.376 billion of long-term debt due after one year.

See Note 12 – Debt and Banking Arrangements for the aggregate maturities over the next five years.

Our potential sources of liquidity available to address these maturities include cash generated from operations, proceeds from refinancing, our credit facility, or our commercial paper program, as well as proceeds from asset monetizations.

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

At December 31, 2023, we had a working capital deficit of $1.317 billion, including cash and cash equivalents and long-term debt due within one year.

Our available liquidity is as follows:

Available Liquidity December 31, 2023

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.

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

As of December 31, 2024, Williams had a working capital deficit of $2.651 billion, including cash and cash equivalents and long-term debt due within one year.

Williams available liquidity is as follows:

December 31, 2024

Cash and cash equivalents $ 60

Capacity available under our $3.75 billion credit facility, less amounts outstanding under our $3.5 billion commercial paper program (1) 3,025

(1) In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program.

We had $725 million of commercial paper outstanding at December 31, 2023.

The highest amount outstanding under our commercial paper program and credit facility during 2023 was $730 million.

At December 31, 2023, we were in compliance with the financial covenants associated with our credit facility.

See Note 12 – Debt and Banking Arrangements for additional information on our credit facility and commercial paper program.

We increased our regular quarterly cash dividend to common stockholders by approximately 5.3 percent from the $0.425 per share paid in each quarter of 2022, to $0.4475 per share paid in each quarter of 2023.

Capacity available under Williams’ $3.75 billion credit facility, less amounts outstanding under Williams’ $3.5 billion 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 expects to be in compliance with the financial covenants associated with the credit facility for the December 31, 2024, 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.

On January 28, 2025, Williams’ board of directors approved a regular quarterly dividend of $0.5000 per share payable on March 31, 2025.

Registrations

Prior to the expiration of our shelf registration statement, we anticipate filing a new shelf registration statement as a well-known seasoned issuer.

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

Distributions from Equity-Method Investees

The organizational documents of entities in which we have an equity-method investment generally require periodic distributions of their available cash to their members.

The organizational documents of entities in which Williams has an equity-method investment generally require periodic distributions of their available cash to their members.

In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses.

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Credit Ratings

The interest rates at which we are able to borrow money are impacted by our credit ratings.

The current ratings are as follows:

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

Rating Agency Outlook Senior Unsecured

S&P Global Ratings Stable BBB

S&P Global Ratings Positive

Moody’s Investors Service Stable Baa2

Fitch Ratings Stable BBB

These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our securities, and each rating should be evaluated independently of any other rating.

No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current

criteria for investment-grade ratios.

A downgrade of our credit ratings might increase our future cost of borrowing and, if ratings were to fall below investment-grade, could require us to provide additional collateral to third parties, negatively impacting our available liquidity.

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.

No assurance can be given that the credit rating agencies will continue to assign Williams investment-grade ratings even if it meets or exceeds their current criteria for investment-grade ratios.

A downgrade of its credit ratings might increase Williams’ future cost of borrowing and, if ratings were to fall below investment-grade, could require it to provide additional collateral to third parties, negatively impacting Williams’ available liquidity.

Management’s Discussion and Analysis (Continued)

Sources (Uses) of Cash

The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table):

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:

Cash Flow Year Ended December 31,

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Sources of cash and cash equivalents:

Net cash provided (used) by operating activities

Operating $ 5,938 $ 4,889 $ 3,945

Proceeds from long-term debt (see Note 12)

Net cash provided (used) by operating activities Operating $ 4,974 $ 5,938 $ 4,889

Proceeds from long-term debt (Note 13)

Financing 3,594 2,755 1,755

Proceeds from (payments of) commercial paper - net

Proceeds from sale of business ( Note 3 )

Investing — 346 —

Proceeds from dispositions of equity-method investments (Note 3)

Investing 161 — —

Proceeds from commercial paper – net

Financing — 372 345

Proceeds from sale of business (see Note 3)

Uses of cash and cash equivalents:

Capital expenditures Investing (2,516) (2,253) (1,239)

Common dividends paid Financing (2,179) (2,071) (1,992)

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

Payments of long-term debt Financing (2,946) (634) (2,876)

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

Investing (2,244) (1,568) (933)

Payments of long-term debt (see Note 12)

Financing (634) (2,876) (894)

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)

Purchases of and contributions to equity-method investments (see Note 8)

Investing (141) (166) (115)

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) (9)

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Operating activities

The factors that determine 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, Inventory write-downs, and Amortization of stock-based awards.

Our 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 .

Our Net cash provided (used) by operating activities in 2022 increased from 2021 primarily due to higher operating income (excluding noncash items as previously discussed), favorable changes in margin requirements, and higher Distributions from equity-method investees , partially offset by net unfavorable changes in net operating working capital.

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

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own (see Note 17 – Contingencies and Commitments).

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

We are 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 $48 million, all of which are included in Accrued and other current liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet at December 31, 2023.

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

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 2023, we paid approximately $7 million for cleanup and/or remediation and monitoring activities.

We expect to pay approximately $9 million in 2024 for these activities.

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

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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.

We continuously monitor these regulatory changes and how they may impact our operations.

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

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

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

Historically, with limited exceptions, we have been permitted recovery of these environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings.

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.

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