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

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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			53
Company Outlook			56

Results of Operations			60
Williams			60
Transco			71
NWP			73
Management’s Discussion and Analysis of Financial Condition and Liquidity			75

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, 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’ CODM 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, including 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

Management’s Discussion and Analysis (Continued)

Pennsylvania, a 66 percent interest in Cardinal which operates in Ohio, 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. 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 include 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 combined notes thereto of this Form 10-Q and the Annual Report on Form 10-K for the year ended December 31, 2024, dated February 25, 2025.

Dividends

In June 2025, Williams paid a regular quarterly dividend of $0.50 per share.

Overview of Six Months Ended June 30, 2025

Net income (loss) attributable to The Williams Companies, Inc. for the six months ended June 30, 2025, increased $204 million compared to the six months ended June 30, 2024. Further discussion of the results is found in this report in the Results of Operations.

Recent Developments

Transco FERC Rate Case Filing

On August 30, 2024, Transco filed a general rate case with the FERC for an overall increase in rates and to comply with the terms of the settlement of its prior rate case. On September 30, 2024, the FERC issued an order accepting and suspending Transco’s general rate filing to be effective March 1, 2025, subject to refund and the outcome of hearing procedures established by the FERC. The order also accepted rate decreases for certain services to be effective as of October 1, 2024. Transco has provided a reserve for rate refunds, which it believes is adequate for any refunds that may be required.

Data Center Power Projects

Williams continues to pursue projects to support the power demands created by new data center development, including an agreement with an unnamed large, investment-grade company to provide onsite natural gas and power generation infrastructure. See Expansion Projects for further discussion of Socrates.

Saber Asset Purchase

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

Management’s Discussion and Analysis (Continued)

Cogentrix Investment

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

Rimrock Asset Purchase

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

Expansion Project Updates

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

Transmission & Gulf of America

Deepwater Shenandoah Project

In June 2021, Williams reached an agreement with two third parties to provide offshore natural gas gathering and transportation services as well as onshore natural gas processing services. The project expands the existing Gulf of America offshore infrastructure connecting to a third-party offshore lateral pipeline from the Shenandoah platform to Discovery’s existing Keathley Canyon Connector pipeline, adds onshore processing facilities at Larose, Louisiana to handle the expected rich Shenandoah production, and the natural gas liquids are now fractionated and marketed at Discovery’s Paradis plant in Louisiana. This project was placed into service in July 2025.

Texas to Louisiana Energy Pathway

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

Southeast Energy Connector

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

Deepwater Whale Project

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

Management’s Discussion and Analysis (Continued)

West

Louisiana Energy Gateway

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

Company Outlook

Williams’ strategy is to provide a large-scale, reliable, and clean energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. Williams accomplishes this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. Williams continues to maintain a strong commitment to safety, environmental stewardship including seeking opportunities for renewable energy ventures, operational excellence, and customer satisfaction. Williams believes that accomplishing these goals will position it 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. Williams also expects to benefit from the recent equity investment in Cogentrix. These increases are partially offset by a modest increase in expenses, lower gas marketing results, 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 $2.575 billion to $2.875 billion, excluding acquisitions. Growth capital spending in 2025 primarily includes the Socrates Power Innovation project, 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.

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;

Management’s Discussion and Analysis (Continued)

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. Risk Factors in the Annual Report on Form 10-K for the year ended December 31, 2024, as filed with the SEC on February 25, 2025, 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 & Gulf of America

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.

Commonwealth Energy Connector

In November 2023, Transco received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity in Virginia. Transco 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 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

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 third quarter of 2027, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 1,597 Mdth/d.

Management’s Discussion and Analysis (Continued)

Gillis West

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

Northeast Supply Enhancement

In May 2025, Transco filed a petition with the FERC 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. Also in May 2025, Transco filed applications with the states of New York, New Jersey, and Pennsylvania for Clean Water Act and related permits for the project. 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.

Dalton Lateral II

Transco plans to file a certificate application for the project with the FERC in 2026. 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.

Ryckman Creek Loop

NWP plans to file a prior notice application for the project with the FERC in 2025. The project 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 2026, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 50 Mdth/d.

Stanfield South

The project involves an expansion of NWP’s existing natural gas transmission system to 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.

Naughton Coal-to-Gas Conversion

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

Kelso-Beaver Reliability

NWP filed a certificate application for the project with the FERC in February 2025. The Kelso-Beaver Reliability project on NWP’s existing natural gas transmission system will provide year-round transportation capacity to various receipt and delivery points in Oregon. NWP plans to place the project into service during the

Management’s Discussion and Analysis (Continued)

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

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

Wild Trail

In May 2025, NWP filed a certificate application with the FERC for the project, which involves an expansion of NWP’s existing natural gas transmission system that will provide year-round transportation capacity from the White River Hub receipt point in western Colorado to various delivery points in southwest Wyoming and southern Colorado. This Wild Trail project is fully subscribed by an affiliate within Williams’ Gas & NGL Marketing Services segment. 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.

Socrates

Williams has received partial approval and is waiting for full approval from the Ohio Power Siting Board for this Power Innovation project, which involves the construction of the Socrates North and South power generation facilities in New Albany, Ohio. Williams has agreed to invest approximately $1.6 billion to provide committed power generation and associated gas pipeline infrastructure for the project, which is expected to provide a combined 400 megawatts of committed onsite power generation capacity to the customer. The project is backed by a ten-year, primarily fixed-price power purchase agreement, with an option for the customer to extend. Williams plans to place the project into service in the second half of 2026, assuming timely receipt of permits.

West

Haynesville Gathering Expansion

In February 2023, Williams announced its agreement with a third party to facilitate natural gas production growth in the Haynesville Shale basin. Williams is constructing a greenfield gathering system in support of a 26,000-acre dedication. In April 2025, the third party sold a majority of their ownership interest to another party. The system, once completed, will provide natural gas gathering services to both parties who have also agreed to long-term capacity commitments on Williams’ Louisiana Energy Gateway expansion project. This project is expected to go into service in third-quarter 2025.

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 and six months ended June 30, 2025, compared to the three and six months ended June 30, 2024, 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 June 30,				Change*			Six Months Ended June 30,				Change*
	2025		2024		$	%		2025		2024		$	%
	(Dollars in millions)							(Dollars in millions)
Revenues:
Service revenues	$	2,041	$	1,837	+204	+11	%	$	4,044	$	3,742	+302	+8	%

Product sales and service revenues – commodity consideration	704		628		+76	+12	%	1,811		1,503		+308	+20	%
Net gain (loss) from commodity derivatives	36		(129)		+165	NM		(26)		(138)		+112	+81	%
Total revenues	2,781		2,336					5,829		5,107
Costs and expenses:
Product costs and net processing commodity expenses	478		441		-37	-8	%	1,121		972		-149	-15	%

Operating and maintenance expenses	572		522		-50	-10	%	1,114		1,033		-81	-8	%
Depreciation, depletion, and amortization expenses	605		540		-65	-12	%	1,190		1,088		-102	-9	%
Selling, general, and administrative expenses	168		164		-4	-2	%	362		350		-12	-3	%




Other (income) expense – net	13		(27)		-40	NM		3		(44)		-47	NM
Total costs and expenses	1,836		1,640					3,790		3,399
Operating income (loss)	945		696					2,039		1,708
Equity earnings (losses)	142		147		-5	-3	%	297		284		+13	+5	%

Other investing income (loss) – net	4		18		-14	-78	%	12		42		-30	-71	%
Interest expense	(350)		(339)		-11	-3	%	(699)		(688)		-11	-2	%

Other income (expense) – net	16		33		-17	-52	%	30		64		-34	-53	%
Income (loss) before income taxes	757		555					1,679		1,410
Less: Provision (benefit) for income taxes	174		129		-45	-35	%	367		322		-45	-14	%


Net income (loss)	583		426					1,312		1,088
Less: Net income attributable to noncontrolling interests	37		25		-12	-48	%	75		55		-20	-36	%
Net income (loss) attributable to The Williams Companies, Inc.	$	546	$	401	+145	+36	%	$	1,237	$	1,033	+204	+20	%

- = 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 June 30, 2025 vs. three months ended June 30, 2024

Service revenues increased primarily due to:

Higher revenues associated with expansion projects and increased transportation and storage rates that became effective March 1, 2025 at the Transmission & Gulf of America segment;

Management’s Discussion and Analysis (Continued)

Higher volumes from the August 2024 Discovery Acquisition at the Transmission & Gulf of America segment (See Note 3 – Acquisitions and Divestitures), the January 2025 Rimrock Asset Purchase, the Haynesville Shale region at the West segment, and the Northeast JV at the Northeast G&P segment;
Higher revenues associated with reimbursable expenses primarily in the Northeast G&P segment, which is offset by similar changes in the charges reflected in Operating and maintenance expenses; partially offset by
Lower revenues in the Eagle Ford Shale region due to lower MVC revenue at the West segment.

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

Higher equity NGL sales and commodity consideration revenues associated with equity NGL production activity primarily driven by the Discovery Acquisition at the Transmission & Gulf of America segment;
Higher product sales from upstream operations primarily related to higher volumes from the November 2024 Crowheart Acquisition at Other (See Note 3 – Acquisitions and Divestitures); partially offset by
Lower marketing sales activities primarily related to lower NGLs marketing sales prices and lower net natural gas marketing sales activity at the Gas & NGL Marketing Services segment.

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

Net gain (loss) from commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues primarily in the Gas & NGL Marketing Services segment, as well as 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 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 increase primarily consists of:

Higher shrink natural gas purchases and commodity consideration costs associated with Williams’ equity NGL production activities primarily due to the Discovery Acquisition at the Transmission & Gulf of America segment; partially offset by
Lower marketing activities primarily related to lower NGLs marketing purchases at the Gas & NGL Marketing Services segment, including from the Discovery Acquisition.

Operating and maintenance expenses increased primarily due to operating costs of the assets acquired at the Transmission & Gulf of America and West segments, as well as at Other and higher electricity and fuel primarily in the Northeast G&P segment (substantially offset by higher Service revenues discussed above).

Depreciation, depletion, and amortization expenses increased primarily related to the increase in depreciation rates effective March 1, 2025 at the Transmission & Gulf of America segment and assets acquired at the Transmission & Gulf of America and West segments, as well as at Other.

Other (income) expense – net within Operating income (loss) includes an unfavorable change in the amortization of regulatory assets and liabilities at the Transmission & Gulf of America segment.

The unfavorable change in Other investing income (loss) – net includes lower interest income earned on lower cash and cash equivalent balances.

Management’s Discussion and Analysis (Continued)

Interest expense was primarily impacted by Williams’ 2024 and 2025 debt issuances, partially offset by 2024 and 2025 debt retirements (see Note 7 – Debt and Banking Arrangements) and the absence of imputed interest on deferred consideration obligations related to previous acquisitions.

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

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.

Six months ended June 30, 2025 vs. six months ended June 30, 2024

Service revenues increased primarily due to:

Higher revenues associated with expansion projects and increased transportation and storage rates that became effective March 1, 2025, at the Transmission & Gulf of America segment;
Higher volumes from the August 2024 Discovery Acquisition at the Transmission & Gulf of America segment (See Note 3 – Acquisitions and Divestitures), January 2025 Rimrock Asset Purchase at the West segment, and the Northeast JV at the Northeast G&P segment;
Higher revenues associated with reimbursable expenses primarily in the Northeast G&P segment, which is offset by similar changes in the charges reflected in Operating and maintenance expenses; partially offset by
Lower revenues in the Eagle Ford Shale region due to lower MVC revenue at the West segment.

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

Higher equity NGL sales and commodity consideration revenues associated with equity NGL production activity primarily due to the Discovery Acquisition at the Transmission & Gulf of America segment and higher prices at the West segment;
Higher marketing sales activities primarily related to higher NGLs marketing sales at the Gas & NGL Marketing Services segment and higher sales prices at the West segment;
Higher product sales from upstream operations primarily related to higher volumes from the November 2024 Crowheart Acquisition at Other (See Note 3 – Acquisitions and Divestitures).

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

Higher marketing activities primarily related to higher NGLs marketing purchases at the Gas & NGL Marketing Services segment;
Higher shrink natural gas purchases and commodity consideration costs associated with Williams’ equity NGL production activities primarily due to the Discovery Acquisition at the Transmission & Gulf of America segment.

Management’s Discussion and Analysis (Continued)

Other (income) expense – net within Operating income (loss) includes an unfavorable change in the amortization of regulatory assets and liabilities and deferral of ARO-related depreciation at the Transmission & Gulf of America segment.

The unfavorable change in Other investing income (loss) – net includes lower interest income earned on lower cash and cash equivalent balances.

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income.

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 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 America



	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
	(Millions)
Service revenues	$	1,176	$	1,023	$	2,311	$	2,072



Product sales and service revenues – commodity consideration (1)	136		45		274		115
Net realized gain (loss) from commodity derivatives (1)	—		—		(1)		—
Segment revenues	1,312		1,068		2,584		2,187



Product costs and net processing commodity expenses (1)	(119)		(40)		(242)		(101)
Other segment costs and expenses	(339)		(269)		(666)		(544)



Proportional Modified EBITDA of equity-method investments	37		49		73		95
Transmission & Gulf of America Modified EBITDA	$	891	$	808	$	1,749	$	1,637

Commodity margins	$	17	$	5	$	31	$	14

(1)Included as a component of Commodity margins.

Management’s Discussion and Analysis (Continued)

Three months ended June 30, 2025 vs. three months ended June 30, 2024

Transmission & Gulf of America 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 $76 million increase in Transco’s revenues primarily associated with expansion projects placed in-service, notably Regional Energy Access in August 2024, Southside Reliability Enhancement in November 2024, Texas Louisiana Energy Pathway in April 2025, and Southeast Energy Connector in April 2025; and transportation and storage rate increases effective during the second quarter of 2024 and March 1, 2025;

*•*A $34 million increase in the Gulf Coast region primarily due to higher gathering and transportation volumes from the Whale expansion project that went in-service in January 2025 and production handling volumes from a new well at Gulfstar One in the Pickerel field;

A $24 million increase primarily in gathering revenues due to the Williams’ Discovery Acquisition in August 2024 (see Note 3 – Acquisitions and Divestitures);
A $9 million increase in Gulf Coast Storage’s revenues primarily associated with higher storage rates.

Commodity margins increased primarily due to the Discovery Acquisition.

Other segment costs and expenses increased primarily due to:

*•*Higher operating expenses and administrative costs including increased operating costs resulting from Williams’ Discovery Acquisition and the absence of a gain associated with MountainWest cash-out sales in 2024;

*•*Unfavorable change in equity AFUDC primarily as a result of the timing of capital projects at Williams’ regulated businesses;

Unfavorable change in the amortization of regulatory assets and liabilities at Transco;
Unfavorable change in the deferral of ARO-related depreciation at Transco.

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

Six months ended June 30, 2025 vs. six months ended June 30, 2024

Transmission & Gulf of America 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 $120 million increase in Transco’s revenues primarily associated with expansion projects placed in service, notably Regional Energy Access in August 2024, Southside Reliability Enhancement in November 2024, Texas Louisiana Energy Pathway in April 2025, and Southeast Energy Connector in April 2025; and transportation and storage rate increases effective during the second quarter of 2024 and March 1, 2025;

*•*A $46 million increase primarily in gathering revenues due to the Discovery Acquisition;

A $44 million increase in the Gulf Coast region primarily due to higher gathering and transportation volumes from the Whale expansion project that went in-service in January 2025 and production handling

Management’s Discussion and Analysis (Continued)

volumes from a new well at Gulfstar One in the Pickerel field, partially offset by shut-ins for maintenance activities at Devil’s Tower impacting the Taggart and Kodiak fields;

A $22 million increase in Gulf Coast Storage’s revenues primarily associated with higher storage rates.

Commodity margins increased primarily due to the Discovery Acquisition.

Other segment costs and expenses increased primarily due to:

*•*Higher operating expenses and administrative costs including increased operating costs resulting from Williams’ Discovery Acquisition, corporate allocations, and employee-related costs; as well as the absence of a gain associated with MountainWest cash-out sales in 2024; partially offset by the absence of acquisition and transition costs related to Williams’ Gulf Coast Storage Acquisition in January 2024 (see Note 3 – Acquisitions and Divestitures);

*•*Unfavorable change in equity AFUDC primarily as a result of the timing of capital projects at Williams’ regulated businesses;

Unfavorable change in the amortization of regulatory assets and liabilities at Transco;
Unfavorable change in the deferral of ARO-related depreciation at Transco.

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

Northeast G&P



	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
	(Millions)
Service revenues	$	497	$	465	$	994	$	944
Product sales and service revenues – commodity consideration (1)	44		18		102		48
Segment revenues	541		483		1,096		992

Product costs and net processing commodity expenses (1)	(38)		(18)		(90)		(37)
Other segment costs and expenses	(156)		(137)		(304)		(280)

Proportional Modified EBITDA of equity-method investments	154		153		313		310
Northeast G&P Modified EBITDA	$	501	$	481	$	1,015	$	985

Commodity margins	$	6	$	—	$	12	$	11

(1)Included as a component of Commodity margins.

Three months ended June 30, 2025 vs. three months ended June 30, 2024

Northeast G&P 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 $17 million increase in revenues at the Northeast JV primarily related to higher gathering, processing, and fractionation volumes, and higher gathering and processing rates;

Management’s Discussion and Analysis (Continued)

A $9 million increase in revenues associated with reimbursable expenses, which is offset by similar changes in the charges reflected in Other segment costs and expenses.

Other segment costs and expenses increased primarily due to higher operating expenses, including higher electricity and fuel (substantially offset by higher Service revenues discussed above).

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

Six months ended June 30, 2025 vs. six months ended June 30, 2024

Northeast G&P 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 $29 million increase in revenues at the Northeast JV primarily related to higher gathering, processing, and fractionation volumes, and higher gathering and processing rates;

A $17 million increase in revenues associated with reimbursable expenses, which is offset by similar changes in the charges reflected in Other segment costs and expenses.

Other segment costs and expenses increased primarily due to higher operating expenses, including higher electricity and fuel (substantially offset by higher Service revenues discussed above).

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

Management’s Discussion and Analysis (Continued)

West



	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
	(Millions)
Service revenues	$	446	$	407	$	884	$	844
Product sales and service revenues – commodity consideration (1)	229		209		518		473

Net realized gain (loss) from commodity derivatives relating to service revenues	—		7		(1)		10
Net realized gain (loss) from commodity derivatives relating to product sales (1)	1		(2)		—		(5)
Net realized gain (loss) from commodity derivatives	1		5		(1)		5

Segment revenues	676		621		1,401		1,322

Product costs and net processing commodity expenses (1)	(201)		(177)		(455)		(426)
Other segment costs and expenses	(166)		(162)		(321)		(312)

Proportional Modified EBITDA of equity-method investments	32		36		70		61
West Modified EBITDA	$	341	$	318	$	695	$	645

Commodity margins	$	29	$	30	$	63	$	42

(1) Included as a component of Commodity margins.

Three months ended June 30, 2025 vs. three months ended June 30, 2024

West Modified EBITDA increased primarily due to higher Service revenues.

Service revenues increased primarily due to:

*•*A $21 million increase in the DJ Basin region primarily associated with the Rimrock Asset Purchase;

A $15 million increase in the Haynesville Shale region primarily due to higher gathering volumes;
An $8 million increase in the Wamsutter region associated with higher gathering volumes;
An $8 million increase in the Barnett Shale region primarily due to higher gathering rates driven by favorable commodity pricing; partially offset by
A $16 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenue.

Net realized gain (loss) from commodity derivatives relating to service revenues is unfavorable due to the absence of realized hedge positions in second-quarter 2025.

Six months ended June 30, 2025 vs. six months ended June 30, 2024

West Modified EBITDA increased primarily due to higher Service revenues and Commodity margins.

Service revenues increased primarily due to:

A $30 million increase in the DJ Basin region primarily due to higher gathering volumes associated with the Rimrock Asset Purchase;

Management’s Discussion and Analysis (Continued)

A $16 million increase in the Haynesville Shale region primarily due to higher gathering volumes;
A $14 million increase in the Barnett Shale region primarily due to higher gathering rates driven by favorable commodity pricing;
An $8 million increase in other NGL operations primarily associated with higher fractionation revenue due to higher volumes and higher rates driven by favorable commodity pricing; partially offset by
A $29 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenue.

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

Commodity margins increased $21 million primarily due to $14 million higher margins from equity NGLs associated with higher net realized NGL sales prices and a $10 million increase in marketing margins from increased sales activities associated primarily with higher prices.

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

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

Gas & NGL Marketing Services



	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
	(Millions)

Product sales (1)	$	403	$	423	$	1,142	$	1,010

Net realized gain (loss) from commodity derivative instruments (1)	2		(33)		(33)		48
Net unrealized gain (loss) from commodity derivative instruments	(16)		(99)		(9)		(197)
Net gain (loss) from commodity derivatives	(14)		(132)		(42)		(149)

Segment revenues	389		291		1,100		861

Product costs (1)	(421)		(387)		(934)		(819)
Net unrealized gain (loss) from commodity derivative instruments within Net processing commodity expenses	12		(7)		2		(4)
Other segment costs and expenses	(18)		(23)		(57)		(63)
Proportional Modified EBITDA of equity-method investments	8		—		11		—
Gas & NGL Marketing Services Modified EBITDA	$	(30)	$	(126)	$	122	$	(25)

Commodity margins	$	(16)	$	3	$	175	$	239

(1) Included as a component of Commodity margins.

Three months ended June 30, 2025 vs. three months ended June 30, 2024

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

Commodity margins decreased $19 million primarily due to an $11 million decrease in natural gas marketing margins, including $27 million of lower natural gas transportation capacity marketing margins due to unfavorable

Management’s Discussion and Analysis (Continued)

net realized pricing spreads. The decrease in natural gas marketing margins was partially offset by $16 million of higher natural gas storage marketing margins primarily driven by favorable realized derivative gains, partially offset by higher storage fees.

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 2024 is primarily due to a change in forward commodity prices relative to hedge positions in 2025 compared to 2024.

Six months ended June 30, 2025 vs. six months ended June 30, 2024

Commodity margins decreased $64 million primarily due to:

A $49 million decrease in natural gas marketing margins, including $51 million of lower natural gas transportation capacity marketing margins due to unfavorable net realized pricing spreads. The decrease in natural gas marketing margins was partially offset by $2 million of higher natural gas storage marketing margins primarily driven by higher withdrawals in 2025 compared to 2024, partially offset by less favorable realized derivative gains.

*•*A $15 million decrease in NGL marketing margins including an unfavorable change in net realized gains and losses on sale of inventory in 2025 compared to 2024 driven by an unfavorable change in NGL prices.

Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and Net processing commodity expenses changed from 2024 primarily due to a change in forward commodity prices relative to hedge positions in 2025 compared to 2024.

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

Other



	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
	(Millions)
Service revenues	$	4	$	4	$	8	$	8
Product sales (1)	137		86		292		194

Net realized gain (loss) from derivative instruments (1)	9		23		7		28
Net unrealized gain (loss) from derivative instruments	40		(25)		11		(22)
Net gain (loss) from commodity derivatives	49		(2)		18		6

Net revenues from upstream operations, corporate, and other business activities.	190		88		318		208

Other costs and expenses	(72)		(41)		(125)		(85)


Modified EBITDA from upstream operations, corporate, and other business activities	$	118	$	47	$	193	$	123

Net realized product sales	$	146	$	109	$	299	$	222

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

Management’s Discussion and Analysis (Continued)

Three months ended June 30, 2025 vs. three months ended June 30, 2024

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

*•*A $65 million favorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to hedge positions;

A $37 million increase in Net realized product sales from our upstream operations primarily due to higher production volumes associated with Williams’ Wamsutter region production, including the Crowheart Acquisition. The second quarter 2025 also benefited from higher net realized gas prices, which were partially offset by lower net realized oil prices compared to second quarter 2024; partially offset by

*•*A $31 million unfavorable change in other costs and expenses primarily related to upstream operations, including an increase from the Crowheart Acquisition in November 2024.

Six months ended June 30, 2025 vs. six months ended June 30, 2024

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

*•*A $77 million increase in Net realized product sales from upstream operations primarily due to higher production volumes and higher net realized commodity prices associated with Williams’ Wamsutter region production, including the Crowheart Acquisition. The first half of 2025 also benefited from higher net realized commodity prices associated with Williams’ South Mansfield production in the Haynesville Shale region;

A $33 million favorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to hedge positions; partially offset by
A $40 million unfavorable change in other costs and expenses primarily related to upstream operations, including an increase from the Crowheart Acquisition in November 2024.

Management’s Discussion and Analysis (Continued)

Transco - Results of Operations


	Six Months Ended June 30,
	2025		$ Change from 2024*	% Change from 2024*		2024
	(Millions)
Revenues:
Natural gas transportation service revenues	$	1,384	+98	+8	%	$	1,286
Natural gas storage service revenues	118		+22	+23	%	96
Natural gas product sales	44		-2	-4	%	46
Other service revenues	15		+1	+7	%	14
Total revenues	1,561					1,442

Costs and expenses:
Natural gas product costs	44		+2	+4	%	46
Operating and maintenance expenses	241		-3	-1	%	238
Selling, general, and administrative expenses	110		-7	-7	%	103
Depreciation and amortization expenses	315		-50	-19	%	265
Taxes, other than income taxes	61		-4	-7	%	57

Other (income) expense – net	21		-46	NM		(25)
Total costs and expenses	792					684

Operating income (loss)	769		+11	+1	%	758

Interest expense	(162)		-1	-1	%	(161)
Interest income	15		-18	-55	%	33
Allowance for equity and borrowed funds used during construction (AFUDC)	15		-35	-70	%	50
Other income (expense) – net	(2)		+1	+33	%	(3)

Net income (loss)	$	635	-42	-6	%	$	677

- = 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.

Six months ended June 30, 2025 vs. six months ended June 30, 2024

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

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

Management’s Discussion and Analysis (Continued)

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

Revenues increased primarily due to:

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

◦The Regional Energy Access Expansion in August 2024;

◦The Southside Reliability Enhancement in November 2024;

◦The Texas Louisiana Energy Pathway in April 2025; and

◦The Southeast Energy Connector in April 2025.

The increase in Natural gas transportation service revenues is also due to transportation rate increases effective March 1, 2025, partially offset by one less billing day in 2025 and lower electric power costs in 2025. 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;

*•*An increase in Natural gas storage service revenues primarily due to an increase in rates that became effective during the second quarter of 2024 and an increase in rates that became effective March 1, 2025;

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

Natural gas product costs changed favorably, 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 higher employee-related costs partially offset by lower electric power costs. Electric power costs are recovered from customers through transportation rates and are offset in Natural gas transportation service revenues resulting in no net impact on results of operations.

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

Other (income) expense – net changed unfavorably primarily driven by an unfavorable change associated with the deferral of ARO related depreciation (offset in Depreciation and amortization expenses resulting in no net impact on Transco’s results of operations), an unfavorable change in the amortization of ARO regulatory assets, an unfavorable change in the amortization of the regulatory pension liabilities, and an unfavorable change in project feasibility costs.

Interest income decreased due to a decrease in affiliated interest income on our advances to Williams due to a lower note receivable balance during 2025.

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

Management’s Discussion and Analysis (Continued)

NWP - Results of Operations


	Six Months Ended June 30,
	2025		$ Change from 2024*		% Change from 2024*		2024
	(Millions)
Revenues:
Natural gas transportation service revenues	$	212	$	+3	+1	%	$	209
Natural gas storage service revenues	8		—		—	%	8
Other service revenues	4		-1		-20	%	5
Total revenues	224						222

Costs and expenses:
Operating and maintenance expenses	45		—		—	%	45
Selling, general, and administrative expenses	24		—		—	%	24
Depreciation and amortization expenses	59		-5		-9	%	54
Taxes, other than income taxes	8		-1		-14	%	7

Other (income) expense - net	(10)		+1		+11	%	(9)
Total costs and expenses	126						121

Operating income (loss)	98		-3		-3	%	101

Interest expense	(14)		—		—	%	(14)
Allowance for equity and borrowed funds used during construction (AFUDC)	4		—		—	%	4
Other income (expense) – net	3		-2		-40	%	5

Net income (loss)	$	91	$	-5	-5	%	$	96

- = 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.

Six months ended June 30, 2025 vs. six months ended June 30, 2024

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

Revenues increased primarily due to:

An increase in Natural gas transportation service revenues primarily due to a cost recovery surcharge effective April 1, 2025, partially offset by one less billing day in 2025 and a decrease in short-term firm transportation;
Partially offset by a decrease in Other service revenues from lower park and loan services.

Management’s Discussion and Analysis (Continued)

Other (income) expense - net changed favorably primarily as a result of projects transferred to capital.

Depreciation and amortization expenses increased due to additional assets placed in service in 2025.

Other income (expense) – net decreased primarily due to a decrease in affiliated interest income on our advances to Williams due to a lower note receivable balance during 2025.

Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity

Outlook

Williams’ growth capital and investment expenditures in 2025 are expected to range from $2.575 billion to $2.875 billion, excluding acquisitions. Growth capital spending in 2025 primarily includes the Socrates Power Innovation project, 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. 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.

During the first six months of 2025, Williams issued $3 billion of long-term debt and retired $750 million of long-term debt (see Note 7 – Debt and Banking Arrangements).

In June 2025, Williams acquired Saber for cash consideration of $47 million and the retention of $113 million of Saber’s debt, which was separately repaid in full within the same month. 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).

As of June 30, 2025, Williams, including consolidated subsidiaries, has approximately $3.0 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 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:


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

Management’s Discussion and Analysis (Continued)

As of June 30, 2025, Williams has approximately $25.6 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 June 30, 2025, Williams had a working capital deficit of $2.791 billion, including cash and cash equivalents and long-term debt due within one year. Williams’ available liquidity is as follows:


	June 30, 2025
	(Millions)
Cash and cash equivalents	$	903
Capacity available under Williams’ $3.75 billion credit facility, less amounts outstanding under Williams’ $3.5 billion commercial paper program (1)	3,750
	$	4,653

(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 as of June 30, 2025. Through June 30, 2025, the highest amount outstanding under the commercial paper program and credit facility during 2025 was $475 million. Williams expects to be in compliance with the financial covenants associated with the credit facility for the June 30, 2025, reporting period.

Dividends

Williams increased the regular quarterly cash dividend to common stockholders from $0.475 per share paid in each quarter of 2024, to $0.50 per share paid in March and June 2025.

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

In April 2025 Moody’s Investors Service changed its Outlook from Stable to Positive. In March 2025 S&P Global Ratings changed its Senior Unsecured Debt Rating to BBB+ with Stable Outlook. 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’

Management’s Discussion and Analysis (Continued)

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.

Sources (Uses) of Cash

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


	Cash Flow	Six Months Ended June 30,
	Category	2025		2024
		(Millions)
Sources of cash and cash equivalents:
Proceeds from long-term debt (Note 7)	Financing	$	2,994	$	2,100
Net cash provided (used) by operating activities	Operating	2,883		2,513






Uses of cash and cash equivalents:
Capital expenditures	Investing	(1,984)		(1,123)
Payments of long-term debt	Financing	(975)		(2,274)
Common dividends paid	Financing	(1,221)		(1,158)

Purchases of and contributions to equity-method investments	Investing	(179)		(82)
Proceeds from (payments of) commercial paper – net	Financing	(454)		(95)
Dividends and distributions paid to noncontrolling interests	Financing	(131)		(130)
Purchases of businesses, net of cash acquired (Note 3)	Investing	(1)		(1,844)


Other sources / (uses) – net	Financing and Investing	(89)		(2)
Increase (decrease) in cash and cash equivalents		$	843	$	(2,095)

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 , Inventory write-downs, and Amortization of stock-based awards.

Williams’ Net cash provided (used) by operating activities for the six months ended June 30, 2025, increased from the same period in 2024, primarily due to favorable changes in margin requirements and net operating working capital, as well as higher operating income (excluding non-cash items previously discussed).

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