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

Combined Management’s Discussion and Analysis of Financial Condition and Results of Operations			Page
General			44
Company Outlook			45
Results of Operations			50
Williams			50
Transco			57
NWP			59
Management’s Discussion and Analysis of Financial Condition and Liquidity			60

General

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

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

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

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

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

Dividends

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

Overview of Three Months Ended March 31, 2026

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

Management’s Discussion and Analysis (Continued)

Recent Developments

Transco FERC Rate Case Filing

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

Sale of Mid-Continent Gathering Assets

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

Sale of South Mansfield Upstream Interests

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

Expansion Project Updates

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

Transmission, Power & Gulf

Naughton Coal-to-Gas Conversion

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

Company Outlook

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

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

Management’s Discussion and Analysis (Continued)

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

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

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

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

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

• Counterparty credit and performance risk;

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

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

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

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

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

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

Expansion Projects

Williams’ ongoing major expansion projects include the following:

Transmission, Power & Gulf

Gillis West

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

Management’s Discussion and Analysis (Continued)

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

Southeast Supply Enhancement

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

Northeast Supply Enhancement

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

Line 200

In April 2023, Driftwood received FERC approval for Line 200, which will connect multiple pipelines to the Louisiana LNG facility. Williams will be the operator of the pipeline and plans to place the project into service as early as the second quarter of 2028. The pipeline has an expected capacity of 3,100 Mdth/d.

Pine Prairie Phase IV Expansion

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

Dalton Lateral II

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

Power Express

Transco plans to file an application with the FERC as early as the second quarter 2027 for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity in Virginia. Transco plans to place the project into service as early as the third quarter of 2030, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 750 Mdth/d.

Management’s Discussion and Analysis (Continued)

Ryckman Creek Loop

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

Huntingdon Connector

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

Wild Trail

In March 2026, NWP received FERC approval for the project, which involves an expansion of NWP’s existing natural gas transmission system that will provide year-round transportation capacity from the White River Hub receipt point in western Colorado to various delivery points in southwest Wyoming and southern Colorado. The Wild Trail project is fully subscribed by an affiliate of NWP. NWP plans to place the project into service during the fourth quarter of 2027, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 83 Mdth/d.

Kelso-Beaver Reliability

In November 2025, NWP received FERC approval for the project, which will provide year-round transportation capacity to various receipt and delivery points in Oregon. NWP plans to place the project into service during the fourth quarter of 2028, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 183 Mdth/d. In May 2026, NWP purchased the 17-mile Kelso-Beaver pipeline, a key milestone for this project.

Silver Spur

NWP plans to file an application with the FERC as early as the second half of 2027 for the project, which will provide year-round transportation capacity from the Rockies Supply hub at Opal, Wyoming to various delivery points in Idaho. NWP plans to place the project into service as early as the first half of 2030, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 275 Mdth/d.

Power Innovation

Socrates

The Socrates project involves the construction of the Socrates North and South power generation facilities and associated gas pipeline infrastructure in New Albany, Ohio, which together have an expected 556 MW of capacity. The project is backed by a 10 year, primarily fixed-price power purchase agreement, with an option for the customer to extend the term of the agreement. Williams has received necessary approvals from the Ohio Power Siting Board. Williams plans to place the project into service in the third and fourth quarter of 2026.

Additional Projects

Williams has agreed to provide committed power generation and associated gas pipeline infrastructure for four additional Power Innovation projects, Apollo, Aquila, Socrates the Younger, and Neo. The projects

Management’s Discussion and Analysis (Continued)

are backed by primarily fixed-price power purchase agreements, with options for the customer to extend the term of the agreements. The Apollo project, in Ohio, has a term of 12.5 years, and Williams expects the project to be placed into service in the second half of 2027 and to provide 490 MW of capacity. The Aquila project, in Utah, also has a term of 12.5 years, and Williams expects the project to be placed into service in the second half of 2027 and the first half of 2028 and to provide 520 MW of capacity. The Socrates the Younger project, in Ohio, has a term of 10 years, and Williams expects the project to be placed into service the second half of 2028 and to provide 340 MW of capacity. The Neo project, in Ohio, has a term of 12.5 years, and Williams expects the project to be placed into service in the second half of 2028 and to provide 682 MW of capacity. All expected in-service dates assume timely receipt of permits.

West

Dorne

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

Other

Lakeland Solar Project

Williams is constructing and will operate a 75 MW alternating current solar power facility interconnecting with Lakeland Electric in Florida. This project is expected to be placed in service in the fourth quarter of 2026.

Management’s Discussion and Analysis (Continued)

Results of Operations

Williams’ Consolidated Overview

The following table and discussion is a summary of Williams’ consolidated results of operations for the three months ended March 31, 2026, compared to the three months ended March 31, 2025, and should be read in conjunction with the results of operations by segment, as discussed in further detail following this consolidated overview discussion.

															Three Months Ended March 31,												Change*
																											2026						2025						$						%
															(Dollars in millions)
Revenues:
Service revenues																											$	2,206					$	2,003					+203						+10		%
Product sales and service revenues – commodity consideration																											1,183						1,107						+76						+7		%
Net gain (loss) from commodity derivatives																											(359)						(62)						-297						NM
Total revenues																											3,030						3,048
Costs and expenses:
Product costs and net processing commodity expenses																											558						643						+85						+13		%
Operating and maintenance expenses																											565						542						-23						-4		%
Depreciation, depletion, and amortization expenses																											584						585						+1						—		%
General and administrative expenses																											193						194						+1						+1		%
Gain on sale of certain assets																											(182)						—						+182						NM
Other operating (income) expense – net																											(9)						(10)						-1						-10		%
Total costs and expenses																											1,709						1,954
Operating income (loss)																											1,321						1,094
Equity earnings (losses)																											161						155						+6						+4		%
Other investing income (loss) – net																											24						8						+16						+200		%
Interest expense																											(376)						(349)						-27						-8		%
Other income (expense) – net																											26						14						+12						+86		%
Income (loss) before income taxes																											1,156						922
Less: Provision (benefit) for income taxes																											244						193						-51						-26		%
Net income (loss)																											912						729
Less: Net income attributable to noncontrolling interests																											47						38						-9						-24		%
Net income (loss) attributable to The Williams Companies, Inc.																											$	865					$	691					+174						+25		%

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

Three months ended March 31, 2026 vs. three months ended March 31, 2025

Service revenues increased primarily due to:

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

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

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

Management’s Discussion and Analysis (Continued)

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

• Lower product sales from upstream operations primarily related to lower volumes, including the first quarter 2026 sale of interests in certain upstream ventures in the South Mansfield area of the Haynesville Shale region (See Note 3 – Divestitures), at Other.

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

Net gain (loss) from commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues primarily in the Gas & NGL Marketing Services segment, as well as upstream operations at Other (see Note 9 – Commodity Derivatives).

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

The Product costs and net processing commodity expenses decrease primarily consists of lower marketing activities related to NGLs at the Gas & NGL Marketing Services segment.

Operating and maintenance expenses increased primarily due to higher operating taxes.

Depreciation, depletion, and amortization expenses decreased primarily related to the sale of certain upstream ventures in the South Mansfield area of the Haynesville Shale region at Other, substantially offset by assets placed in service at the West segment.

Gain on sale of certain assets reflects a gain from the sale of certain upstream ventures in the South Mansfield area of the Haynesville Shale region in 2026, at Other.

Interest expense was primarily impacted by 2025 and 2026 debt issuances and retirements (see Note 7 – Debt and Banking Arrangements), partially offset by higher interest capitalized due to ongoing expansion projects.

Provision (benefit) for income taxes changed unfavorably primarily due to 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.

Period-Over-Period Operating Results – Williams’ Segments

Williams’ CODM evaluates segment operating performance based upon Modified EBITDA. Note 11 – Segment Disclosures includes a reconciliation of this non-GAAP measure to Income (loss) before income taxes. Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the

Management’s Discussion and Analysis (Continued)

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, Power & Gulf

									Three Months Ended March 31,
															2026						2025
															(Millions)
Service revenues															$	1,287					$	1,135
Product sales and service revenues – commodity consideration (1)															155						138
Net realized gain (loss) from commodity derivatives (1)															(1)						(1)
Segment revenues															1,441						1,272
Product costs and net processing commodity expenses (1)															(136)						(123)
Other segment costs and expenses															(332)						(327)
Proportional Modified EBITDA of equity-method investments															37						36
Transmission, Power & Gulf Modified EBITDA															$	1,010					$	858
Commodity margins															$	18					$	14

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(1)Included as a component of Commodity margins.

Three months ended March 31, 2026 vs. three months ended March 31, 2025

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

Service revenues increased primarily due to:

• A $68 million increase in Transco’s revenues primarily associated with expansion projects placed in service, notably Texas Louisiana Energy Pathway in April 2025, Southeast Energy Connector in April 2025, Commonwealth Energy Connector in November 2025, and Alabama Georgia Connector in October 2025; and transportation and storage rate increases;

• A $25 million increase in Gulf Coast Storage’s revenues primarily associated with higher park and loan services and higher storage rates;

• A $19 million increase in Discovery’s revenues primarily in natural gas gathering revenues due to volumes from the Shenandoah expansion project that went in-service in July 2025;

• A $13 million increase in the Western Gulf Coast region primarily due to higher natural gas gathering and crude oil transportation volumes from the Whale expansion project that went in-service in January 2025;

*•*A $10 million increase in the Eastern Gulf Coast region primarily due to higher crude oil transportation and natural gas gathering volumes from new wells at Blind Faith in the Ballymore field;

• An $8 million increase in NWP’s revenues primarily due to transportation rate increases.

Management’s Discussion and Analysis (Continued)

Other segment costs and expenses increased primarily due to:

• Higher operating expenses and administrative costs including higher employee-related costs as well as increased corporate allocations and property taxes; partially offset by

*•*Favorable change in equity AFUDC primarily from Driftwood Pipeline’s Line 200 and other capital projects within the regulated businesses.

Northeast G&P

									Three Months Ended March 31,
															2026						2025
															(Millions)
Service revenues															$	504					$	497
Product sales and service revenues – commodity consideration (1)															39						58
Segment revenues															543						555
Product costs and net processing commodity expenses (1)															(39)						(52)
Other segment costs and expenses															(148)						(148)
Proportional Modified EBITDA of equity-method investments															168						159
Northeast G&P Modified EBITDA															$	524					$	514
Commodity margins															$	—					$	6

(1)Included as a component of Commodity margins.

Three months ended March 31, 2026 vs. three months ended March 31, 2025

Northeast G&P Modified EBITDA increased primarily due to higher Proportional Modified EBITDA of equity-method investments and higher Service revenues.

Service revenues increased primarily due to:

*•*A $16 million increase in revenues at the Northeast JV primarily related to higher transportation & fractionation volumes, higher gathering volumes, and higher processing rates;

• An $8 million increase in revenues associated with reimbursable expenses, which is offset by similar changes in the charges included in Other segment costs and expenses; partially offset by

*•*A $17 million decrease in gathering revenues at Susquehanna Supply Hub primarily related to lower volumes.

Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments primarily driven by escalated gathering rates and higher gathering volumes.

Management’s Discussion and Analysis (Continued)

West

									Three Months Ended March 31,
															2026						2025
															(Millions)
Service revenues															$	506					$	438
Product sales and service revenues – commodity consideration (1)															250						289
Net realized gain (loss) from commodity derivatives relating to service revenues															(1)						(1)
Net realized gain (loss) from commodity derivatives relating to product sales (1)															—						(1)
Net realized gain (loss) from commodity derivatives															(1)						(2)
Segment revenues															755						725
Product costs and net processing commodity expenses (1)															(219)						(254)
Other segment costs and expenses															(165)						(155)
Proportional Modified EBITDA of equity-method investments															36						38
West Modified EBITDA															$	407					$	354
Commodity margins															$	31					$	34

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(1) Included as a component of Commodity margins.

Three months ended March 31, 2026 vs. three months ended March 31, 2025

West 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 $54 million increase in the Haynesville Shale region primarily due to higher gathering volumes including those resulting from Louisiana Energy Gateway which was placed into service in third-quarter 2025 and the acquisition of Saber Midstream, LLC in June 2025;

• An $11 million increase in the DJ Basin region primarily due to higher gathering volumes, including those associated with the acquisition of natural gas gathering and processing assets from Rimrock Energy Partners, LLC on January 31, 2025; partially offset by

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

Other segment costs and expenses increased primarily due to higher operating expenses, including operating taxes, associated with Louisiana Energy Gateway.

Management’s Discussion and Analysis (Continued)

Gas & NGL Marketing Services

									Three Months Ended March 31,
															2026						2025
															(Millions)
Product sales (1)															$	853					$	739
Net realized gain (loss) from commodity derivative instruments (1)															(127)						(35)
Net unrealized gain (loss) from commodity derivative instruments															(192)						7
Net gain (loss) from commodity derivatives															(319)						(28)
Segment revenues															534						711
Product costs (1)															(478)						(513)
Net unrealized gain (loss) from commodity derivative instruments within Net processing commodity expenses															—						(10)
Other segment costs and expenses															(34)						(39)
Proportional Modified EBITDA of equity-method investments															18						3
Gas & NGL Marketing Services Modified EBITDA															$	40					$	152
Commodity margins															$	248					$	191

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(1) Included as a component of Commodity margins.

Three months ended March 31, 2026 vs. three months ended March 31, 2025

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

Commodity margins increased $57 million primarily due to a $50 million increase in natural gas marketing margins, including $32 million of higher natural gas transportation capacity marketing margins and $18 million of higher natural gas storage marketing margins, both primarily driven by favorable net realized pricing spreads.

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 2025 is primarily due to a change in forward commodity prices relative to hedge positions in 2026 compared to 2025.

Proportional Modified EBITDA of equity-method investments increased driven by the investment in Cogentrix, which was purchased in March 2025.

Management’s Discussion and Analysis (Continued)

Other

									Three Months Ended March 31,
															2026						2025
															(Millions)
Service revenues															$	4					$	4
Product sales (1)															143						155
Net realized gain (loss) from derivative instruments (1)															(5)						(2)
Net unrealized gain (loss) from derivative instruments															(33)						(29)
Net gain (loss) from commodity derivatives															(38)						(31)
Net revenues from upstream operations, corporate, and other business activities.															109						128
Other costs and expenses															(59)						(53)
Gain on sale of certain assets															182						—
Modified EBITDA from upstream operations, corporate, and other business activities															$	232					$	75
Net realized product sales															$	138					$	153

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

Three months ended March 31, 2026 vs. three months ended March 31, 2025

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

*•*A $182 million Gain on sale of certain assets from the sale of certain South Mansfield upstream interests, which was completed in January 2026.

• A $15 million decrease in Net realized product sales from upstream operations driven by the sale of the South Mansfield interests.

• An increase of $6 million in Other costs and expenses primarily due to higher upstream operating expenses in the Wamsutter region, including of higher production expenses and higher ad valorem and production taxes both driven by increased volumes during 2026. These increases were partially offset by a decrease in upstream operating expenses associated with the sale South Mansfield interests.

Management’s Discussion and Analysis (Continued)

Transco - Results of Operations

						Three Months Ended March 31,
						2026						$ Change from 2025*						% Change from 2025*						2025
						(Millions)
Revenues:
Natural gas transportation service revenues						$	751					+61						+9		%				$	690
Natural gas storage service revenues						58						+3						+5		%				55
Natural gas product sales						27						+9						+50		%				18
Other service revenues						11						+4						+57		%				7
Total revenues						847																		770
Costs and expenses:
Natural gas product costs						27						-9						-50		%				18
Operating and maintenance expenses						134						-10						-8		%				124
Depreciation and amortization expenses						144						+5						+3		%				149
General and administrative expenses						59						-2						-4		%				57
Taxes, other than income taxes						33						-3						-10		%				30
Other operating (income) expense – net						4						+2						+33		%				6
Total costs and expenses						401																		384
Operating income (loss)						446						+60						+16		%				386
Interest expense						(86)						-5						-6		%				(81)
Interest income						12						+4						+50		%				8
Allowance for equity and borrowed funds used during construction (AFUDC)						12						+3						+33		%				9
Other income (expense) – net						—						+1						+100		%				(1)
Net income (loss)						$	384					+63						+20		%				$	321

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

Three months ended March 31, 2026 vs. three months ended March 31, 2025

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

Management’s Discussion and Analysis (Continued)

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

Revenues increased primarily due to:

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

◦The Texas Louisiana Energy Pathway in April 2025;

◦The Southeast Energy Connector in April 2025;

◦The Commonwealth Energy Connector in November 2025; and

◦The Alabama Georgia Connector in October 2025.

The increase in Natural gas transportation service revenues is also due to transportation rate increases, higher electric power revenue, and higher seasonal services, partially offset by decreases in short-term firm transportation and commodity revenues. Electric power costs are recovered from Transco’s customers through transportation rates and are offset in Operating and maintenance expenses resulting in no net impact on Transco’s results of operations.

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

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

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

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

Operating and maintenance expenses increased primarily due to an increase in contractor service costs, an increase in employee-related costs, and higher 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. This was partially offset by lower natural gas fuel expense due to favorable pricing.

Depreciation and amortization expenses decreased due to lower negative salvage rate. This was partially offset by an increase related to new assets placed into service.

Management’s Discussion and Analysis (Continued)

NWP - Results of Operations

						Three Months Ended March 31,
						2026						$ Change from 2025*						% Change from 2025*						2025
						(Millions)
Revenues:
Natural gas transportation service revenues						$	114					$	+9					+9		%				$	105
Natural gas storage service revenues						4						—						—		%				4
Other service revenues						2						—						—		%				2
Total revenues						120																		111
Costs and expenses:
Operating and maintenance expenses						23						-2						-10		%				21
Depreciation and amortization expenses						30						-1						-3		%				29
General and administrative expenses						13						—						—		%				13
Taxes, other than income taxes						4						—						—		%				4
Other operating (income) expense – net						(5)						-1						-17		%				(6)
Total costs and expenses						65																		61
Operating income (loss)						55						+5						+10		%				50
Interest expense						(8)						-1						-14		%				(7)
Allowance for equity and borrowed funds used during construction (AFUDC)						2						—						—		%				2
Other income (expense) – net						3						+2						+200		%				1
Net income (loss)						$	52					$	+6					+13		%				$	46

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

Three months ended March 31, 2026 vs. three months ended March 31, 2025

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

Revenues increased primarily due to higher Natural gas transportation service revenues driven by rate increases effective April 1, 2025, and increased firm transportation revenues from new contracts executed at higher rates to replace expiring contracts.

Operating and maintenance expenses increased primarily due to higher labor costs and contracted services related to integrity assessments.

Other income (expense) – net increased primarily due to higher intercompany interest income earned on NWP’s advances to affiliates, driven by higher outstanding balances in 2026.

Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity

Outlook

Williams’ growth capital and investment expenditures in 2026 are expected to range from $7.0 billion to $7.6 billion, as previously discussed in Company Outlook.

On January 8, 2026, Williams issued $2.8 billion of long-term debt and on March 2, 2026, Williams retired $1.1 billion of long-term debt (see Note 7 – Debt and Banking Arrangements).

As of March 31, 2026, Williams, including consolidated subsidiaries, had $0.2 billion of long-term debt due within one year. Williams’ potential sources of liquidity available to address these maturities include cash on hand, proceeds from refinancing, the credit facility, or the commercial paper program, as well as proceeds from asset monetizations.

Liquidity

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

Sources:
			Cash and cash equivalents on hand
			Cash generated from operations
			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
			Proceeds from asset monetizations
Uses:
			Working capital requirements
			Capital and investment expenditures
			Product costs
			Gas & NGL Marketing Services payments for transportation and storage capacity and gas supply
			Other operating costs, including human capital expenses
			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
			Distributions to noncontrolling interests
			Share repurchase program

As of March 31, 2026, Williams had $30.1 billion of long-term debt due after one year. Potential sources of liquidity available to address these maturities include cash generated from operations, proceeds from refinancing, the credit facility, the commercial paper program, and proceeds from asset monetizations.

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

Management’s Discussion and Analysis (Continued)

As of March 31, 2026, Williams had a working capital deficit of $0.7 billion, including cash and cash equivalents and long-term debt due within one year. Williams’ available liquidity is as follows:

						March 31, 2026
						(Millions)
Cash and cash equivalents						$	950
Capacity available under Williams’ $3,750 million credit facility, less amounts outstanding under Williams’ $3,500 million commercial paper program (1)						3,750
						$	4,700

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(1)In managing its available liquidity, Williams does not expect a maximum outstanding amount in excess of the capacity of its credit facility inclusive of any outstanding amounts under its commercial paper program. Williams had no Commercial paper outstanding at March 31, 2026. Through March 31, 2026, the highest amount outstanding under the commercial paper program and credit facility during 2026 was $735 million. Williams expects to be in compliance with the financial covenants associated with the credit facility for the March 31, 2026, reporting period.

Dividends

Williams increased the regular quarterly cash dividend to common stockholders from $0.500 per share paid in each quarter of 2025, to $0.525 per share paid in March 2026.

Distributions from Equity-Method Investees

The organizational documents of entities in which Williams has an equity-method investment generally require periodic distributions of their available cash to their members. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses.

Credit Ratings

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 Debt Rating
S&P Global Ratings						Stable						BBB+
Moody’s Investors Service						Positive						Baa2
Fitch Ratings						Positive						BBB

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 in Williams’ Consolidated Statement of Cash Flows:

			Cash Flow						Three Months Ended March 31,
			Category						2026						2025
									(Millions)
Sources of cash and cash equivalents:
Proceeds from long-term debt			Financing						$	2,768					$	1,497
Net cash provided (used) by operating activities			Operating						1,603						1,433
Dispositions – net (Note 3)			Investing						369						—
Proceeds from sale of business (Note 8)			Investing						48						—
Uses of cash and cash equivalents:
Capital expenditures			Investing						(1,359)						(1,012)
Payments of long-term debt			Financing						(1,109)						(853)
Payments of commercial paper – net			Financing						(699)						(132)
Common dividends paid			Financing						(642)						(610)
Dividends and distributions paid to noncontrolling interests			Financing						(67)						(69)
Purchases of and contributions to equity-method investments			Investing						(29)						(163)
Other sources / (uses) – net			Financing and Investing						4						(51)
Increase (decrease) in cash and cash equivalents									$	887					$	40

Operating activities

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

Williams’ Net cash provided (used) by operating activities for the three months ended March 31, 2026 increased from the three months ended March 31, 2025 primarily due to higher operating income (excluding noncash items previously discussed), partially offset by unfavorable changes in margin requirements.