NORTHWEST PIPELINE LLC

Williams’ Consolidated Overview

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

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

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

•Higher volumes from the August 2024 Discovery Acquisition at the Transmission, Power & Gulf segment, the June 2025 Saber Asset Purchase and the January 2025 Rimrock Asset Purchase at the West segment, and higher volumes from the Northeast JV at the Northeast G&P segment;

•Higher revenues associated with reimbursable expenses primarily in the Northeast G&P segment, which is offset by similar changes in the charges reflected in Operating and maintenance expenses; partially offset by

•Lower revenues in the Eagle Ford Shale region due to lower MVC revenue at the West segment.

The net sum of Product sales and service revenues – commodity consideration, Product costs and net processing commodity expenses, and net realized gains and losses on commodity derivatives related to sales of product and shrink gas purchases for processing plants for the reportable segments comprise Commodity Margins. 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 product sales from upstream operations primarily related to higher volumes, including the November 2024 Crowheart Acquisition (See Note 3 – Acquisitions and Divestitures), and natural gas prices at Other;

•Higher equity NGL sales and commodity consideration revenues associated with equity NGL production activity primarily due to the Discovery Acquisition at the Transmission, Power & Gulf segment;

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

•Higher cash-out activity primarily at the Transmission, Power & Gulf segment.

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

Net gain (loss) from commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues primarily in the Gas & NGL Marketing Services segment, as well as upstream operations at Other (see Note 17 – Commodity Derivatives).

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

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

•Higher shrink natural gas purchases and commodity consideration costs associated with Williams’ equity NGL production activities primarily due to the Discovery Acquisition at the Transmission, Power & Gulf segment;

•Higher cash-out activity primarily at the Transmission, Power & Gulf segment; partially offset by

•Lower marketing activities primarily related to NGL’s at the Gas & NGL Marketing Services segment.

Operating and maintenance expenses increased primarily due to operating costs of the assets acquired at the Transmission, Power & Gulf and West segments, as well as upstream operations at Other, and higher electricity and fuel primarily in the Northeast G&P segment (substantially offset by higher Service revenues discussed above), partially offset by the absence of the impact of a 2024 change in practice related to payroll timing.

Depreciation, depletion, and amortization expenses increased primarily related to assets acquired and expansion projects placed in-service at the Transmission, Power & Gulf and West segments, as well as upstream operations at Other and an increase in Transco depreciation rates associated with the rate case at the Transmission, Power & Gulf segment, partially offset by lower ARO-related depreciation at the Transmission, Power & Gulf segment.

General and administrative expenses increased due to higher employee-related costs, partially offset by lower acquisition and transition costs primarily at the Transmission, Power & Gulf segment and the absence of the impact of a 2024 change in a practice related to payroll timing.

Impairment or write-off of certain assets includes an impairment to certain assets held for sale in the Mid-Continent region and the write-off of certain DJ Basin region assets in the West segment in 2025.

The unfavorable change in Other (income) expense – net within Operating income (loss) includes net unfavorable changes to charges and credits associated with amortization of regulatory assets and liabilities related to the Transco rate case and deferral of ARO-related depreciation at the Transmission, Power & Gulf segment.

Equity earnings (losses) changed favorably primarily due to the impact of $153 million from our investment Cogentrix in 2025 (see Note 8 – Investing Activities) and increases at Blue Racer and Appalachia Midstream Investments.

The unfavorable change in Other investing income (loss) – net includes the absence of a $149 million gain on the sale of our interests in Aux Sable in 2024 (see Note 8 – Investing Activities), a $127 million gain on remeasurement of our existing equity-method investment associated with the purchase of the remaining interest in Discovery in 2024, and lower interest income earned on lower cash and cash equivalent balances.

Interest expense was primarily impacted by 2024 and 2025 debt issuances, partially offset by 2024 and 2025 debt retirements and the absence of imputed interest on deferred consideration obligations related to previous acquisitions (see Note 13 – Debt and Banking Arrangements).

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

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income and the absence of a benefit associated with a decrease in the estimate of the state deferred income tax rate in 2024. See Note 6 – Provision (Benefit) for Income Taxes for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

•Higher volumes from the November 2023 DJ Basin Acquisitions at the West segment and the January 2024 Gulf Coast Storage, August 2024 Discovery, and February 2023 MountainWest Acquisitions at the Transmission, Power & Gulf segment; partially offset by lower volumes from the September 2023 sale of certain liquids pipelines at the Transmission, Power & Gulf segment (see Note 3 – Acquisitions and Divestitures),

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

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

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

•Higher marketing sales activities primarily at the West segment primarily related to the DJ Basin Acquisitions and Transmission, Power & Gulf segment primarily related to the Discovery Acquisition; partially offset by lower marketing sales activities related to NGLs at the Gas & NGL Marketing Services segment, primarily related to activity associated with the sale certain liquids pipelines. Net natural gas marketing sales were impacted by higher storage costs; partially offset by

•Lower system management gas sales primarily at the Transmission, Power & Gulf segment;

•Lower product sales from upstream operations; partially offset by higher volumes from the November 2024 Crowheart Acquisition at Other;

•Lower equity NGL sales and commodity consideration revenues associated with NGL production activity primarily at the West segment; partially offset by higher activity in the Transmission, Power & Gulf segment primarily due to the Discovery Acquisition.

Net gain (loss) from commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues primarily in the Gas & NGL Marketing Services and West segments, and upstream operations at Other.

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

•Higher marketing activities primarily at the West segment primarily related to the DJ Basin Acquisitions and Transmission, Power & Gulf segment primarily related to the Discovery Acquisition; partially offset by lower marketing activities primarily related to NGLs at the Gas & NGL Marketing Services segment; partially offset by

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

Operating and maintenance expenses increased primarily due to operating costs of the assets acquired at the West and Transmission, Power & Gulf segments; as well as unfavorable changes in employee-related costs, including the impact of a change in a practice related to payroll timing; and the net imbalance liability due to changes in pricing.

Depreciation, depletion, and amortization expenses increased primarily related to the assets acquired at the Transmission, Power & Gulf and West segments and an increase at Transco related to additional assets placed in service. The increase is partially offset by lower amortization of intangibles related to the acquisition of Sequent Energy Management, L.P. and Sequent Energy Canada, Corp. (Sequent) in 2021.

General and administrative expenses increased primarily due to employee-related costs, including the impact of a change in a practice related to payroll timing, partially offset by lower acquisition and transition-related costs associated with the MountainWest Acquisition (see Note 3 – Acquisitions and Divestitures).

Gain on sale of business reflects a gain from the sale of certain liquids pipelines in the Transmission, Power & Gulf segment in 2023.

Other (income) expense – net within Operating income (loss)includes lower project feasibility costs at our Transmission, Power & Gulf segment; partially offset by the absence of a 2023 gain related to a contract settlement.

Equity earnings (losses) changed unfavorably primarily due to the impacts of the consolidation of RMM and Discovery, and the sale of the interests in Aux Sable (see Note 8 – Investing Activities), partially offset by the absence of the share of a loss contingency accrual in 2023 at Aux Sable and favorable results at OPPL.

Other investing income (loss) – net includes gains on the sale of the interests in Aux Sable and the gain on remeasuring the existing equity-method investment in Discovery to fair value with the acquisition of the remaining 40 percent ownership, partially offset by the absence the 2023 gain on remeasuring the existing equity-method investment in RMM to fair value with the acquisition of the remaining 50 percent ownership (see Note 8 – Investing Activities).

The increase in Interest expense was primarily due to Williams’ 2023 and 2024 debt issuances, and imputed interest on deferred consideration obligations related to the DJ Basin and Gulf Coast Storage Acquisitions, partially offset by 2023 and 2024 debt retirements.

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

Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income and a higher benefit associated with decreases in the estimate of the state deferred income tax rate in both periods.

Income (loss) from discontinued operations in 2023 includes a pre-tax charge of $125 million to increase the accrued liability associated with the Alaska refinery contamination litigation, partially offset by the related income tax effect (see Note 1 – Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).

Period-Over-Period Operating Results – Williams’ Segments

Williams’ CODM evaluates segment operating performance based upon Modified EBITDA. Note 19 – Segment Disclosures includes a reconciliation of this non-GAAP measure to Income (loss) before income taxes. Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. 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.

(1)Included as a component of Commodity margins.

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

•A $291 million increase in Transco’s revenues primarily associated with expansion projects placed in service, notably Regional Energy Access in August 2024, Southside Reliability Enhancement in November 2024, Texas Louisiana Energy Pathway in April 2025, and Southeast Energy Connector in April 2025; and transportation and storage rate increases;

•A $96 million increase in the Western Gulf Coast region primarily due to higher natural gas gathering and crude oil transportation volumes from the Whale expansion project that went in-service in January 2025;

•A $78 million increase primarily in natural gas gathering revenues due to the Discovery Acquisition and volumes from the Shenandoah expansion project that went in-service in July 2025 (see Note 3 – Acquisitions and Divestitures);

•A $49 million increase in the Eastern Gulf Coast region primarily due to higher production handling, crude oil transportation and natural gas gathering volumes from new wells at Gulfstar One in the Pickerel field and at Blind Faith in the Ballymore field and the absence of shut-ins due to weather-related events, partially offset by shut-ins for maintenance activities at Devils Tower impacting the Taggart and Kodiak fields;

•A $45 million increase in Gulf Coast Storage’s revenues primarily associated with higher storage rates;

•A $14 million increase in NWP’s revenues primarily due to transportation rate increases.

Commodity margins increased primarily due to the Discovery Acquisition.

Other segment costs and expenses increased primarily due to:

•Unfavorable change in equity AFUDC primarily as a result of the timing of capital projects within the regulated businesses;

•Net unfavorable changes in charges and credits associated with regulatory assets and liabilities related to the rate case at Transco;

•Higher operating expenses and administrative costs including increased operating costs resulting from the Discovery Acquisition, corporate allocations, and property taxes, as well as higher employee-related costs, partially offset by the absence of acquisition and transition costs related to the Gulf Coast Storage Acquisition in January 2024 (see Note 3 – Acquisitions and Divestitures) and a 2024 change in a practice related to payroll timing;

•Unfavorable change in the deferral of ARO-related depreciation at Transco; partially offset by

•A net favorable change related to certain asset retirements in the Western Gulf Coast region in 2025.

Proportional Modified EBITDA of equity-method investments decreased primarily due to lower proportional results as Discovery was consolidated following its August 2024 acquisition.

Transmission, Power & Gulf Modified EBITDA increased primarily due to higher Service revenues, partially offset by the absence of a Gain on sale of business, higher Other segment costs and expenses, and lower Proportional Modified EBITDA of equity-method investments.

•A $220 million increase primarily in storage revenues due to the Gulf Coast Storage Acquisition in January 2024 (see Note 3 – Acquisitions and Divestitures);

•A $121 million increase in Transco’s revenues primarily associated with expansion projects and higher park and loan services;

•A $41 million increase primarily in gathering revenues due to the Discovery Acquisition in August 2024;

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

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

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

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

Other segment costs and expenses increased primarily due to:

•Higher operating expenses and administrative costs including higher operating, acquisition and transition costs related to Williams’ Gulf Coast Storage and Discovery Acquisitions, and employee-related costs, including the impact of a change in a practice related to payroll timing; partially offset by significantly lower acquisition and transition costs related to Williams’ MountainWest Acquisition, contract services at Transco, and operating costs related to the sale of certain liquids pipelines in the Gulf Coast region;

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

•Lower project feasibility costs;

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

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

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

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

Northeast G&P

(1)Included as a component of Commodity margins.

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

•A $40 million increase in revenues at the Northeast JV primarily related to higher transportation & fractionation volumes, higher gathering volumes, and higher processing rates;

•A $29 million increase in revenues associated with reimbursable expenses, which is offset by similar changes in the charges reflected in Other segment costs and expenses;

•An $11 million increase in gathering revenues in the Utica Shale region primarily related to higher volumes at Cardinal; partially offset by

•A $6 million decrease in gathering revenues at Susquehanna Supply Hub primarily related to lower volumes partially offset by escalated rates.

Other segment costs and expenses increased primarily due to higher operating expenses, including higher electricity and fuel (substantially offset by higher Service revenues discussed above) and higher maintenance expenses. The increase was partially offset by lower employee-related costs related to the absence of the impact of a 2024 change in a practice related to payroll timing.

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

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

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

•A $16 million increase in joint venture operating fees primarily related to assuming operatorship of Blue Racer effective January 1, 2024, (which is significantly offset by higher Other segment costs and expenses discussed below);

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

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

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

Commodity margins increased due to a restructured gas purchase deal in 2024 which allowed for margin gain on residue pricing and liquids from fixed recoveries. In addition, Williams was not significantly impacted by system constraints which impacted margins in 2023.

Other segment costs and expenses increased primarily due to higher employee-related costs, including the impact of a change in a practice related to payroll timing, as well as higher operating expenses, including higher electricity and fuel, and increased support costs related to assuming operatorship of Blue Racer effective January 1, 2024 (substantially offset by higher Service revenues discussed above). The increase was partially offset by lower maintenance expenses and the absence of the 2023 loss contingency accrual.

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

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

West

(1) Included as a component of Commodity margins.

West Modified EBITDA decreased primarily due to the 2025 Impairment or write-off of certain assets, partially offset by higher Service revenues.

•A $121 million increase in the Haynesville Shale region primarily due to higher gathering volumes including those resulting from Louisiana Energy Gateway which was placed into service in third-quarter 2025 and the Saber Asset Purchase;

•A $60 million increase in the DJ Basin region primarily due to higher gathering volumes associated with the Rimrock Asset Purchase;

•A $17 million increase in the Barnett Shale region primarily due to higher gathering rates driven by favorable commodity pricing; partially offset by

•A $77 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenue.

Commodity margins increased $21 million primarily due to $12 million higher margins from equity NGLs associated with higher net realized NGL sales prices as well as higher volumes of equity NGL sold, and a $12 million increase in marketing margins primarily associated with the DJ Basin Acquisitions, as previously discussed.

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

Impairment or write-off of certain assets reflects the $176 million impairment of Mid-Continent assets held for sale, and $36 million write-off of certain compression and processing assets in the DJ Basin region.

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

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

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

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

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

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

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

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

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

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

Commodity margins increased $63 million primarily due to $39 million higher margins associated with the DJ Basin Acquisitions, as previously discussed. Margins also increased $21 million from Williams’ equity NGLs primarily due to lower net realized prices for natural gas purchases and lower volumes of natural gas purchased both associated with equity NGL production activities; partially offset by lower volumes of equity NGL sold and lower net realized NGL sales prices.

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

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

Gas & NGL Marketing Services

(1) Included as a component of Commodity margins.

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

Commodity margins decreased $99 million primarily due to:

•An $83 million decrease in natural gas marketing margins, including $105 million of lower natural gas transportation capacity marketing margins due to unfavorable net realized pricing spreads. The decrease in natural gas marketing margins was partially offset by $22 million of higher natural gas storage marketing margins primarily driven by higher withdrawals in 2025 compared to 2024, partially offset by less favorable realized derivative gains;

•A $16 million decrease in NGL marketing margins including an unfavorable change in net realized gains and losses on sale of inventory in 2025 compared to 2024 driven by an unfavorable change in NGL prices.

Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and Net processing commodity expenses relates to derivative contracts that are not designated as hedges for accounting purposes. The change from 2024 is primarily due to a change in forward commodity prices relative to hedge positions in 2025 compared to 2024.

Other segment costs and expenses decreased primarily due to lower employee-related costs.

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

Gas & NGL Marketing Services Modified EBITDA decreased primarily due to an unfavorable change in Net unrealized gain (loss) from commodity derivative instruments and lower Commodity margins.

Commodity margins decreased $64 million primarily due to:

•A $44 million decrease in natural gas marketing margins including $35 million of lower natural gas transportation capacity marketing margins due to less favorable net realized pricing spreads. The decrease in natural gas marketing margins also includes $9 million of lower natural gas storage marketing margins primarily driven by higher storage fees and less favorable realized derivative gains, partially offset by a favorable change of $14 million in lower cost or net realizable value inventory adjustment;

•A $20 million decrease in NGL marketing margins including an unfavorable change in net realized gains and losses on sale of inventory in 2024 compared to 2023 driven by unfavorable changes in non-ethane prices.

Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and Net processing commodity expenses changed from 2023 primarily due to a change in forward commodity prices relative to hedge positions in 2024 compared to 2023.

Other

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

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

•A $161 million increase in Net realized product sales from upstream operations consisting of a $143 million increase at the Wamsutter region and an $18 million increase at the Haynesville Shale region. The Wamsutter region increased primarily due to higher production volumes, including from the November 2024 Crowheart Acquisition, and higher net realized natural gas prices, partially offset by lower net realized oil and NGL prices. The Haynesville region benefited from higher net realized natural gas prices, partially offset by lower production volumes, associated with South Mansfield production in the Haynesville Shale region;

•A $36 million favorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to hedge positions; partially offset by

•A $57 million unfavorable change in other costs and expenses primarily related to upstream operations, including an increase from the Crowheart Acquisition in November 2024, and an unfavorable change associated with regulatory assets related to the effects of deferred taxes on equity funds used during construction.

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

•A $34 million decrease in Net realized product sales from upstream operations primarily due to lower volumes and lower net realized commodity prices associated with Williams’ South Mansfield production in the Haynesville Shale region, and lower net realized commodity prices associated with Williams’ Wamsutter region. These decreases were partially offset by higher production volumes associated with Williams’ Wamsutter region production, including from the Crowheart Acquisition in the fourth quarter of 2024.

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

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

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