Combined Management’s Discussion and Analysis of Financial Condition and Results of Operations Page General 50 Company Outlook 52 Results of Operations 57 Williams 57 Transco 68 NWP 70 Management’s Discussion and Analysis of Financial Condition and Liquidity 71 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 (See Note 1 – Description of Business and Basis of Presentation). All remaining business activities, including upstream operations and corporate activities, are included in Other. 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 June 2026, Williams paid a regular quarterly dividend of $0.525 per share. Overview of Six Months Ended June 30, 2026 Net income (loss) attributable to The Williams Companies, Inc. for the six months ended June 30, 2026, increased $455 million compared to the six months ended June 30, 2025. Further discussion of the results is found in this report in the Results of Operations. 50 Table of Contents Management’s Discussion and Analysis (Continued) Recent Developments Momentum Midstream Acquisition In July 2026, Williams agreed to acquire Momentum for total consideration up to $5.5 billion, including approximately $2 billion of Williams common stock, subject to certain holding restrictions. Momentum’s assets in the Haynesville Shale region include 6 Bcf/d of gathering capacity and 4 Bcf/d of pipeline capacity. The transaction is expected to close later this year, subject to customary closing conditions and regulatory approvals. Power Innovation Joint Venture In July 2026, Williams sold a 49 percent noncontrolling interest in five power innovation projects, Socrates, Apollo, Aquila, Socrates the Younger, and Neo, to an investor in exchange for $5.34 billion of committed capital. The initial July 2026 contribution of approximately $3.75 billion is expected to increase both Capital in excess of par value and Noncontrolling interests in consolidated subsidiaries, reflecting the change in Williams’ ownership interest while retaining control as an equity transaction. The balance of the committed capital is expected to be received through early 2027. Cash distributions will generally align with ownership percentages and distributions to the investor in excess of a target return will serve to reduce its investment balance. In addition, Williams has a buyout right between years 7 and 14 based on the investor’s outstanding investment balance, preserving Williams’ long-term upside in the projects. Sale of Permian Interests Consolidated Permian Gathering Assets In June 2026, Williams signed an agreement to sell certain gas gathering assets in the Permian basin within its West segment. These operations were designated as held for sale at June 30, 2026. Williams expects to recognize a gain upon closing in the third quarter of 2026. See Note 3 – Divestitures. Brazos Permian II Equity-Method Investment In June 2026, Williams completed the sale of an equity-method investment in Brazos Permian II, LLC within its West segment for total consideration of $143 million, resulting in the recognition of a $127 million gain reflected in the second quarter of 2026. See Note 3 – Divestitures. 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 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 February 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 7 – Fair Value Measurements and Guarantees. 51 Table of Contents Management’s Discussion and Analysis (Continued) 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 and an additional gain of $12 million in the second 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 Power Innovation- Socrates The project consists 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. Socrates South was placed into service in late July 2026. Socrates North remains under construction and is expected to be placed into service later in the fourth quarter of 2026. The project is supported 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. 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 contracted 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, including the recently announced Momentum acquisition. 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 $7.3 billion to $7.9 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 canceled. Growth capital 52 Table of Contents Management’s Discussion and Analysis (Continued) 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 July 2026, Transco was authorized under its FERC blanket certificate to proceed with the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Louisiana to delivery points in Texas. Transco plans to place the project into service as early as the 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. 53 Table of Contents Management’s Discussion and Analysis (Continued) 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. Leidy Access Transco plans to file an application with the FERC by fourth quarter of 2026 for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity on the Leidy Line. 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 183 Mdth/d. Line 200 In April 2023, Driftwood received FERC approval for Line 200, which will connect a pipeline 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 May 2026, Williams received the FERC approval 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 800 Mdth/d. Ryckman Creek Lateral In February 2026, NWP was authorized under its FERC blanket certificate to proceed with the project, which involves an expansion of NWP’s existing natural gas transmission system to provide incremental firm 54 Table of Contents Management’s Discussion and Analysis (Continued) 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 contracted capacity by 50 Mdth/d. Huntingdon Connector In May 2026, NWP was authorized under its FERC blanket certificate to proceed with 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 provide 83 Mdth/d of new firm transportation service through a combination of increasing capacity and utilizing existing capacity. 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 second quarter of 2030, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 275 Mdth/d. Power Innovation 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 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. 55 Table of Contents Management’s Discussion and Analysis (Continued) 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. Shelby Trough Connector The project is designed to provide access to growing Haynesville production in the Shelby Trough area through the construction of 64 miles of new lateral pipeline and additional compression facilities connecting to the Louisiana Energy Gateway system. The project is expected to provide 750 MMcf/d of transportation capacity, with expansion capabilities up to 1.5 Bcf/d, and is expected to be placed into service during the second quarter of 2028. Delta Access The project, which is subject to completion of the Momentum acquisition, is designed to provide additional transmission capacity to serve growing power generation and LNG demand through an expansion along the Transco corridor. The project is expected to provide 2,250 Mdth/d of transportation capacity, with additional expansion opportunities, and is expected to be placed into service during the first quarter of 2029. 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. 56 Table of Contents 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, 2026, compared to the three and six months ended June 30, 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 June 30, Change* Six Months Ended June 30, Change* 2026 2025 $ % 2026 2025 $ % (Dollars in millions) Revenues: Service revenues $ 2,152 $ 2,041 +111 +5 % $ 4,358 $ 4,044 +314 +8 % Product sales and service revenues – commodity consideration 807 704 +103 +15 % 1,990 1,811 +179 +10 % Net gain (loss) from commodity derivatives 94 36 +58 +161 % (265) (26) -239 NM Total revenues 3,053 2,781 6,083 5,829 Costs and expenses: Product costs and net processing commodity expenses 515 478 -37 -8 % 1,073 1,121 +48 +4 % Operating and maintenance expenses 597 572 -25 -4 % 1,162 1,114 -48 -4 % Depreciation, depletion, and amortization expenses 592 605 +13 +2 % 1,176 1,190 +14 +1 % General and administrative expenses 180 168 -12 -7 % 373 362 -11 -3 % Gain on sale of certain assets (12) — +12 NM (194) — +194 NM Other operating (income) expense – net (1) 13 +14 NM (10) 3 +13 NM Total costs and expenses 1,871 1,836 3,580 3,790 Operating income (loss) 1,182 945 2,503 2,039 Equity earnings (losses) 159 142 +17 +12 % 320 297 +23 +8 % Other investing income (loss) – net 134 4 +130 NM 158 12 +146 NM Interest expense (371) (350) -21 -6 % (747) (699) -48 -7 % Other income (expense) – net 32 16 +16 +100 % 58 30 +28 +93 % Income (loss) before income taxes 1,136 757 2,292 1,679 Less: Provision (benefit) for income taxes 260 174 -86 -49 % 504 367 -137 -37 % Net income (loss) 876 583 1,788 1,312 Less: Net income attributable to noncontrolling interests 49 37 -12 -32 % 96 75 -21 -28 % Net income (loss) attributable to The Williams Companies, Inc. $ 827 $ 546 +281 +51 % $ 1,692 $ 1,237 +455 +37 % _______ * + = 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. 57 Table of Contents Management’s Discussion and Analysis (Continued) Three months ended June 30, 2026 vs. three months ended June 30, 2025 Service revenues increased primarily due to: •Higher revenues associated with expansion projects at the West and the Transmission, Power & Gulf segments; •Higher volumes from the Northeast JV at the Northeast G&P segment; •Increased 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 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 NGL marketing sales activities and net gas marketing sales activities at the Gas & NGL Marketing Services segment; •Higher product sales from upstream operations primarily related to higher volumes in the Wamsutter region, substantially offset by lower volumes from the January 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 8 – 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 increase primarily consists of higher marketing activities related to NGLs at the Transmission, Power & Gulf and Gas & NGL Marketing Services segments. Operating and maintenance expenses increased primarily due to higher employee-related costs and operating taxes. Depreciation, depletion, and amortization expenses decreased primarily related to lower Transco rates at the Transmission, Power & Gulf segment and the sale of the South Mansfield interests at Other, partially offset by assets placed in service at the West segment. Gain on sale of certain assets reflects an additional gain from the sale of the South Mansfield interests, at Other. Other investing income (loss) – net reflects a gain from the sale of an equity-method investment in Brazos Permian II, LLC at the West segment. 58 Table of Contents Management’s Discussion and Analysis (Continued) Interest expense was unfavorably impacted by 2025 and 2026 debt issuances, partially offset by 2025 and 2026 debt retirements (see Note 6 – Debt and Banking Arrangements) and higher interest capitalized due to ongoing expansion projects. Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income. See Note 5 – 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, 2026 vs. six months ended June 30, 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 rates and Gulf Coast storage rates at the Transmission, Power & Gulf segment; •Higher volumes from the Northeast JV at the Northeast G&P segment. 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 and 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 from the sale of the South Mansfield interests; partially offset by higher volumes in the Wamsutter region, at Other. 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. The Product costs and net processing commodity expenses decrease primarily consists of lower marketing activities related to NGLs at the West and Gas & NGL Marketing Services segments. Operating and maintenance expenses increased primarily due to higher operating taxes and employee-related expenses. Depreciation, depletion, and amortization expenses decreased primarily related to lower Transco rates at the Transmission, Power & Gulf segment and the sale of the South Mansfield interests at Other, partially offset by assets placed in service at the West segment. Gain on sale of certain assets reflects gains from the sale of the South Mansfield interests, at Other. Other investing income (loss) – net reflects a gain from the sale of an equity-method investment in Brazos Permian II, LLC at the West segment. Interest expense was unfavorably impacted by 2025 and 2026 debt issuances, partially offset by 2025 and 2026 debt retirements and higher interest capitalized due to ongoing expansion projects. The favorable change in Other income (expense) – net includes an increase in equity AFUDC primarily as a result of capital projects at the regulated businesses. Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income. 59 Table of Contents Management’s Discussion and Analysis (Continued) Period-Over-Period Operating Results – Williams’ Segments Williams’ CODM evaluates segment operating performance based upon Modified EBITDA. Note 10 – 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, Power & Gulf Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (Millions) Service revenues $ 1,237 $ 1,176 $ 2,524 $ 2,311 Product sales and service revenues – commodity consideration (1) 152 136 307 274 Net realized gain (loss) from commodity derivatives (1) (4) — (5) (1) Segment revenues 1,385 1,312 2,826 2,584 Product costs and net processing commodity expenses (1) (135) (119) (271) (242) Other segment costs and expenses (327) (339) (659) (666) Proportional Modified EBITDA of equity-method investments 36 37 73 73 Transmission, Power & Gulf Modified EBITDA $ 959 $ 891 $ 1,969 $ 1,749 Commodity margins $ 13 $ 17 $ 31 $ 31 _______________ (1)Included as a component of Commodity margins. Three months ended June 30, 2026 vs. three months ended June 30, 2025 Transmission, Power & Gulf Modified EBITDA increased primarily due to higher Service revenues and lower Other segment costs and expenses. Service revenues increased primarily due to: •A $16 million increase in Gulf Coast Storage’s revenues primarily associated with higher storage rates; •A $13 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 Transco’s revenues primarily associated with expansion projects placed in-service, notably Commonwealth Energy Connector in November 2025; •A $6 million increase in MountainWest’s revenues primarily due to the Overthrust Westbound Compression expansion project that went in-service in November 2025. Other segment costs and expenses decreased primarily due to: •Favorable change in equity AFUDC primarily from Driftwood Pipeline’s Line 200 and other capital projects within the regulated businesses; partially offset by •Higher operating expenses and administrative costs including higher employee-related costs. 60 Table of Contents Management’s Discussion and Analysis (Continued) Six months ended June 30, 2026 vs. six months ended June 30, 2025 Transmission, Power & Gulf Modified EBITDA increased primarily due to higher Service revenues. Service revenues increased primarily due to: •An $81 million increase in Transco’s revenues primarily associated with expansion projects placed in service, notably Commonwealth Energy Connector in November 2025, Texas Louisiana Energy Pathway in April 2025, Southeast Energy Connector in April 2025, and Alabama Georgia Connector in October 2025; as well as transportation rate increases and higher park and loan services; •A $41 million increase in Gulf Coast Storage’s revenues primarily associated with higher storage rates and higher park and loan services; •A $32 million increase in Discovery’s revenues primarily in natural gas gathering revenues due to volumes from the Shenandoah expansion project; •A $14 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, partially offset by a decrease at Devil’s Tower related to lower volumes from the Kodiak field; •A $14 million increase in NWP’s revenues primarily due to transportation rate increases; •A $12 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 MountainWest’s revenues primarily due to the Overthrust Westbound Compression expansion project. Other segment costs and expenses decreased primarily due to: •Favorable change in equity AFUDC primarily from Driftwood Pipeline’s Line 200 and other capital projects within the regulated businesses; partially offset by •Higher operating expenses and administrative costs including higher employee-related costs, and increased corporate allocations. 61 Table of Contents Management’s Discussion and Analysis (Continued) Northeast G&P Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (Millions) Service revenues $ 529 $ 497 $ 1,033 $ 994 Product sales and service revenues – commodity consideration (1) 18 44 57 102 Segment revenues 547 541 1,090 1,096 Product costs and net processing commodity expenses (1) (18) (38) (57) (90) Other segment costs and expenses (157) (156) (305) (304) Proportional Modified EBITDA of equity-method investments 168 154 336 313 Northeast G&P Modified EBITDA $ 540 $ 501 $ 1,064 $ 1,015 Commodity margins $ — $ 6 $ — $ 12 (1)Included as a component of Commodity margins. Three months ended June 30, 2026 vs. three months ended June 30, 2025 Northeast G&P Modified EBITDA increased primarily due to higher Service revenues and higher Proportional Modified EBITDA of equity-method investments. Service revenues increased primarily due to: •A $22 million increase in revenues at the Northeast JV primarily related to higher gathering, processing, transportation, and fractionation volumes; and •A $4 million increase in gathering revenues at Susquehanna Supply Hub primarily related to escalated gathering rates. Proportional Modified EBITDA of equity-method investments increased at Blue Racer primarily driven by new MVC revenue, and higher transportation and fractionation volumes; and at Appalachia Midstream Investments primarily driven by escalated gathering rates and higher gathering volumes. Six months ended June 30, 2026 vs. six months ended June 30, 2025 Northeast G&P Modified EBITDA increased primarily due to higher Proportional Modified EBITDA of equity-method investments and higher Service revenues, partially offset by lower Commodity margins. Service revenues increased primarily due to: •A $38 million increase in revenues at the Northeast JV primarily related to higher gathering, processing, transportation, and fractionation volumes; •A $13 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 $14 million decrease in gathering revenues at Susquehanna Supply Hub primarily related to lower volumes, partially offset by escalated rates. 62 Table of Contents Management’s Discussion and Analysis (Continued) Other segment costs and expenses increased due higher operating expenses, including higher electricity and fuel, substantially offset by favorable changes in revaluation of a net imbalance liability due to changes in pricing. Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments primarily driven by higher gathering volumes and escalated gathering rates; and at Blue Racer primarily driven by new MVC revenue, higher gathering rates, and higher volumes. Commodity margins decreased as a result of the expiration of a restructured gas purchase agreement in 2025. West Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (Millions) Service revenues $ 476 $ 446 $ 982 $ 884 Product sales and service revenues – commodity consideration (1) 249 229 499 518 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) (2) 1 (2) — Net realized gain (loss) from commodity derivatives (1) 1 (2) (1) Segment revenues 724 676 1,479 1,401 Product costs and net processing commodity expenses (1) (219) (201) (438) (455) Other segment costs and expenses (181) (166) (346) (321) Proportional Modified EBITDA of equity-method investments 35 32 71 70 West Modified EBITDA $ 359 $ 341 $ 766 $ 695 Commodity margins $ 28 $ 29 $ 59 $ 63 ________________ (1) Included as a component of Commodity margins. Three months ended June 30, 2026 vs. three months ended June 30, 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 $47 million increase in the Haynesville Shale region primarily due to contributions from Louisiana Energy Gateway which was placed into service in the third quarter of 2025, as well as higher gathering volumes including those from the acquisition of Saber Midstream, LLC in June 2025; partially offset by •A $9 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenue and lower gathering volumes. Other segment costs and expenses increased primarily due to higher operating and maintenance expenses, including operating taxes, associated with Louisiana Energy Gateway. 63 Table of Contents Management’s Discussion and Analysis (Continued) Six months ended June 30, 2026 vs. six months ended June 30, 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 $101 million increase in the Haynesville Shale region primarily due to contributions from Louisiana Energy Gateway which was placed into service in the third quarter of 2025, as well as higher gathering volumes including those from the acquisition of Saber Midstream, LLC in June 2025; •A $13 million increase in the Piceance region primary due to higher commodity-price driven processing rates and higher volumes; •A $10 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 $19 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenue; •A $10 million decrease in the Mid-Continent region primarily due to the sale of certain gas gathering assets in February 2026. Other segment costs and expenses increased primarily due to higher operating expenses, including operating taxes, associated with Louisiana Energy Gateway. Gas & NGL Marketing Services Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (Millions) Product sales (1) $ 548 $ 403 $ 1,401 $ 1,142 Net realized gain (loss) from commodity derivative instruments (1) (29) 2 (156) (33) Net unrealized gain (loss) from commodity derivative instruments 119 (16) (73) (9) Net gain (loss) from commodity derivatives 90 (14) (229) (42) Segment revenues 638 389 1,172 1,100 Product costs (1) (507) (421) (985) (934) Net unrealized gain (loss) from commodity derivative instruments within Net processing commodity expenses 1 12 1 2 Other segment costs and expenses (19) (18) (53) (57) Proportional Modified EBITDA of equity-method investments 10 8 28 11 Gas & NGL Marketing Services Modified EBITDA $ 123 $ (30) $ 163 $ 122 Commodity margins $ 12 $ (16) $ 260 $ 175 ________________ (1) Included as a component of Commodity margins. Three months ended June 30, 2026 vs. three months ended June 30, 2025 Gas & NGL Marketing Services Modified EBITDA increased primarily due to a favorable change in Net unrealized gain (loss) from commodity derivative instruments and higher Commodity margins. 64 Table of Contents Management’s Discussion and Analysis (Continued) Commodity margins increased $28 million primarily due to: •A $21 million increase in natural gas marketing margins, including $28 million of higher natural gas transportation capacity marketing margins driven by favorable net realized pricing spreads; •A $7 million increase in NGL marketing margins including a favorable change in net realized gains and losses on sales of inventory driven by a favorable change in NGL prices. Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and Net processing commodity expenses changed from 2025 primarily due to a change in forward commodity prices relative to hedge positions in 2026 compared to 2025. Six months ended June 30, 2026 vs. six months ended June 30, 2025 Gas & NGL Marketing Services Modified EBITDA increased primarily due to higher Commodity margins and Proportional Modified EBITDA of equity-method investments, partially offset by an unfavorable change in Net unrealized gain (loss) from commodity derivative instruments. Commodity margins increased $85 million primarily due to: •A $71 million increase in natural gas marketing margins, including $60 million of higher natural gas transportation capacity marketing margins and $11 million of higher natural gas storage marketing margins, both primarily driven by favorable net realized pricing spreads; •A $14 million increase in NGL marketing margins including a favorable change in net realized gains and losses on sales of inventory driven by a favorable change in NGL prices. Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and Net processing commodity expenses changed from 2025 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. 65 Table of Contents Management’s Discussion and Analysis (Continued) Other Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 (Millions) Service revenues $ 4 $ 4 $ 8 $ 8 Product sales (1) 138 137 281 292 Net realized gain (loss) from derivative instruments (1) (13) 9 (18) 7 Net unrealized gain (loss) from derivative instruments 22 40 (11) 11 Net gain (loss) from commodity derivatives 9 49 (29) 18 Net revenues from upstream operations, corporate, and other business activities. 151 190 260 318 Other costs and expenses (65) (72) (124) (125) Gain on sale of certain assets 12 — 194 — Modified EBITDA from upstream operations, corporate, and other business activities $ 98 $ 118 $ 330 $ 193 Net realized product sales $ 125 $ 146 $ 263 $ 299 ________________ (1) Included as a component of Net realized product sales. Three months ended June 30, 2026 vs. three months ended June 30, 2025 Modified EBITDA from upstream operations, corporate, and other business activities decreased primarily due to: •A $21 million decrease in Net realized product sales from our upstream operations consisting of a $25 million decrease driven by the January 2026 sale of certain South Mansfield upstream interests. There was a $4 million increase at the Wamsutter region due to higher production volumes, partially offset by lower net realized natural gas prices; •An $18 million unfavorable 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 $12 million additional Gain on sale of certain assets from the sale of the South Mansfield interests; •A decrease of $7 million in Other costs and expenses primarily due to the absence of upstream operating expenses associated with the sale of the South Mansfield interests. Six months ended June 30, 2026 vs. six months ended June 30, 2025 Modified EBITDA from upstream operations, corporate, and other business activities increased primarily due to: •A $194 million Gain on sale of certain assets from the sale of the South Mansfield interests; •A decrease in Other costs and expenses primarily due to lower upstream operating expenses associated with the sale of the South Mansfield interests, offset by an increase in upstream operating expenses related to Wamsutter region driven by higher production volumes; partially offset by 66 Table of Contents Management’s Discussion and Analysis (Continued) •A $36 million decrease in Net realized product sales from upstream operations consisting of a $43 million decrease driven by the sale of the South Mansfield interests. There was a $7 million increase at the Wamsutter region primarily due to higher production volumes, partially offset by lower net realized gas prices; •A $22 million unfavorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to hedge positions. 67 Table of Contents Management’s Discussion and Analysis (Continued) Transco - Results of Operations Six Months Ended June 30, Change* 2026 $ % 2025 (Dollars in Millions) Revenues: Natural gas transportation service revenues $ 1,454 +70 +5 % $ 1,384 Natural gas storage service revenues 117 -1 -1 % 118 Natural gas product sales 54 +10 +23 % 44 Other service revenues 26 +11 +73 % 15 Total revenues 1,651 1,561 Costs and expenses: Natural gas product costs 54 -10 -23 % 44 Operating and maintenance expenses 252 -11 -5 % 241 Depreciation and amortization expenses 290 +25 +8 % 315 General and administrative expenses 115 -5 -5 % 110 Taxes, other than income taxes 64 -3 -5 % 61 Other operating (income) expense – net 9 +12 +57 % 21 Total costs and expenses 784 792 Operating income (loss) 867 769 Interest expense (169) -7 -4 % (162) Interest income 23 +8 +53 % 15 Allowance for equity and borrowed funds used during construction (AFUDC) 29 +14 +93 % 15 Other income (expense) – net 1 +3 NM (2) Net income (loss) $ 751 +116 +18 % $ 635 _______ * + = 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, 2026 vs. six months ended June 30, 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 different quantities of gas on Transco’s behalf than the quantities of gas received from Transco. These transactions 68 Table of Contents Management’s Discussion and Analysis (Continued) result in gas transportation and exchange imbalance receivables and payables. Transco’s tariff includes a method whereby the majority of transportation imbalances are settled on a monthly basis through cash out sales or purchases. The net cash out activity has 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 Commonwealth Energy Connector in November 2025; ◦The Texas Louisiana Energy Pathway in April 2025; ◦The Southeast Energy Connector in April 2025; and ◦The Alabama Georgia Connector in October 2025. The increase in Natural gas transportation service revenues is also due to transportation rate increases and higher electric power revenue, partially offset by decreases in commodity revenues and short-term firm transportation. 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 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. Operating and maintenance expenses increased primarily due to an increase in contractor service costs, higher electric power costs, and an increase in employee-related 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 rates. This was partially offset by an increase related to new assets placed into service. General and administrative expenses increased primarily due to higher employee-related costs. Other operating (income) expense – net changed favorably primarily due to lower project feasibility costs. Interest expense was primarily impacted by 2025 debt issuances and a retirement. Interest income increased due to higher interest income on advances to Williams due to a higher note receivable balance during 2026. Allowance for equity and borrowed funds used during construction (AFUDC) increased as a result of higher eligible capital expenditures. 69 Table of Contents Management’s Discussion and Analysis (Continued) NWP - Results of Operations Six Months Ended June 30, Change* 2026 $ % 2025 (Dollars in Millions) Revenues: Natural gas transportation service revenues $ 226 +14 +7 % $ 212 Natural gas storage service revenues 7 -1 -13 % 8 Other service revenues 5 +1 +25 % 4 Total revenues 238 224 Costs and expenses: Operating and maintenance expenses 52 -7 -16 % 45 Depreciation and amortization expenses 61 -2 -3 % 59 General and administrative expenses 25 -1 -4 % 24 Taxes, other than income taxes 8 — — % 8 Other operating (income) expense – net (10) — — % (10) Total costs and expenses 136 126 Operating income (loss) 102 98 Interest expense (17) -3 -21 % (14) Interest income 7 +5 NM 2 Allowance for equity and borrowed funds used during construction (AFUDC) 6 +2 +50 % 4 Other income (expense) – net 1 — — % 1 Net income (loss) $ 99 +8 +9 % $ 91 _______ * + = 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, 2026 vs. six months ended June 30, 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 contracted services related to integrity assessments. Interest expense was primarily impacted by a 2025 debt issuance and retirement. Interest income increased primarily due to higher interest income earned on advances to Williams, driven by higher outstanding balances in 2026. 70 Table of Contents Management’s Discussion and Analysis (Continued) Management’s Discussion and Analysis of Financial Condition and Liquidity Outlook As previously discussed in Company Outlook, Williams’ growth capital and investment expenditures in 2026 are expected to range from $7.3 billion to $7.9 billion, excluding acquisitions and certain long-lead time equipment for power innovation projects that are backed by reimbursement from the customer if the equipment order is canceled. As previously discussed in Recent Developments, Williams received approximately $3.75 billion in July 2026 related to selling a 49 percent noncontrolling interest in five power innovation projects. Williams is expected to receive the remainder of the $5.34 billion of committed capital through early 2027. Also in July 2026, Williams agreed to acquire Momentum for total consideration of up to $5.5 billion, including approximately $2 billion of Williams common stock, subject to certain holding restrictions. As of June 30, 2026, Williams, including consolidated subsidiaries, had $2.2 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. 2026 Long-Term Debt Activity 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 6 – Debt and Banking Arrangements). 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 71 Table of Contents Management’s Discussion and Analysis (Continued) As of June 30, 2026, Williams had $28.1 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. As of June 30, 2026, Williams had a working capital deficit of $3.4 billion, including cash and cash equivalents and long-term debt due within one year. Effective May 19, 2026, Williams, together with Transco and NWP, extended the maturity of the Williams Credit Agreement to 2031 and entered into the new 364-Day Credit Agreement. Transco and NWP are each subject to borrowing sublimits of $500 million under the existing facility and $100 million under the new facility. See Note 6 – Debt and Banking Arrangements. Williams’ available liquidity is as follows: June 30, 2026 (Millions) Cash and cash equivalents $ 203 Capacity available under the Williams Credit Agreement, less amounts outstanding under Williams’ $3.5 billion commercial paper program (1)(2) 3,275 Capacity available under the 364-Day Credit Agreement (2) 1,000 $ 4,478 __________ (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 $475 million of Commercial paper outstanding at June 30, 2026. Through June 30, 2026, the highest amount outstanding under the commercial paper program and credit facility during 2026 was $735 million. (2)Williams expects to be in compliance with the associated financial covenants for the June 30, 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 and June 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. 72 Table of Contents Management’s Discussion and Analysis (Continued) 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. 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 Six Months Ended June 30, Category 2026 2025 (Millions) Sources of cash and cash equivalents: Net cash provided (used) by operating activities Operating $ 2,979 $ 2,883 Proceeds from long-term debt Financing 2,790 2,994 Dispositions – net (Note 3) Investing 345 — Proceeds from sale of business (Note 3) Investing 48 — Uses of cash and cash equivalents: Capital expenditures Investing (3,193) (1,984) Common dividends paid Financing (1,284) (1,221) Payments of long-term debt Financing (1,119) (975) Payments of commercial paper – net Financing (224) (454) Dividends and distributions paid to noncontrolling interests Financing (140) (131) Purchases of and contributions to equity-method investments Investing (91) (179) Dispositions – net Investing — (40) Other sources / (uses) – net Financing and Investing 29 (50) Increase (decrease) in cash and cash equivalents $ 140 $ 843 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, Gain on sale of certain assets, Net unrealized (gain) loss from 73 Table of Contents Management’s Discussion and Analysis (Continued) commodity derivative instruments, Gain on disposition of equity-method investments, Inventory write-downs, and Amortization of stock-based awards. Williams’ Net cash provided (used) by operating activities for the six months ended June 30, 2026, increased from the six months ended June 30, 2025, primarily due to higher operating income (excluding noncash items previously discussed), partially offset by unfavorable changes in net operating working capital in 2026, which includes the payment of Transco’s rate refunds in 2026, and unfavorable changes in margin requirements. 74 Table of Contents