NORTHWEST PIPELINE LLC

Williams’ Consolidated Overview

The following table and discussion is a summary of Williams’ consolidated results of operations for the three and nine months ended September 30, 2025, compared to the three and nine months ended September 30, 2024, and should be read in conjunction with the results of operations by segment, as discussed in further detail following this consolidated overview discussion.

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

•Increased Transco transportation rates, as well as adjustments associated with the rate case at the Transmission, Power & Gulf segment;

•Higher volumes from the August 2024 Discovery Acquisition at the Transmission, Power & Gulf segment (See Note 3 – Acquisitions and Divestitures) and the June 2025 Saber Asset Purchase and the January 2025 Rimrock Asset Purchase at the West segment; partially offset by

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

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

•Higher product sales from upstream operations primarily related to higher volumes from the November 2024 Crowheart Acquisition at Other (See Note 3 – Acquisitions and Divestitures); partially offset by

•Lower marketing sales activities primarily related to lower NGLs marketing sales prices at the Gas & NGL Marketing Services segment.

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

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

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

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

•Lower marketing activities primarily related to lower NGLs marketing purchases at the Gas & NGL Marketing Services segment, including from the Discovery Acquisition;

•Lower 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.

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 at Other, substantially offset by lower employee-related costs, including the absence of the impact of a 2024 change in practice related to payroll timing.

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

Other (income) expense – net within Operating income (loss)includes a write-off of certain DJ Basin region assets in the West segment (see Note 8 – Fair Value Measurements and Guarantees).

The unfavorable change in Other investing income (loss) – net includes a $149 million gain on the sale of our interests in Aux Sable in 2024 and a $127 million gain on remeasurement of our existing equity-method investment associated with the purchase of the remaining interest in Discovery in 2024.

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

Provision (benefit) for income taxes changed unfavorably primarily due to an increase in the estimate of the state deferred income tax rate. 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 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, January 2025 Rimrock Asset Purchase and the June 2025 Saber Asset Purchase at the West segment, and the Northeast JV at the Northeast G&P segment;

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

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

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

•Higher product sales from upstream operations primarily related to higher volumes, including the November 2024 Crowheart Acquisition, 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 and higher prices at the West segment;

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

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

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

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.

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 at Other, higher electricity and fuel primarily in the

Northeast G&P segment (substantially offset by higher Service revenues discussed above) and higher employee-related costs, 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 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.

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

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 and a write-off of certain DJ Basin region assets in the West segment.

The unfavorable change in Other investing income (loss) – net includes a $149 million gain on the sale of our interests in Aux Sable in 2024, 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 Williams’ 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.

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 at Williams’ regulated businesses.

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income and an increase in the estimate of the state deferred income tax rate.

Period-Over-Period Operating Results – Williams’ Segments

Williams’ CODM evaluates segment operating performance based upon Modified EBITDA. Note 11 – Segment Disclosures includes a reconciliation of this non-GAAP measure to Income (loss) before income taxes. Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of Williams’ assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.

(1)Included as a component of Commodity margins.

Transmission, Power & Gulf Modified EBITDA increased primarily due to higher Service revenues.

•An $88 million increase in Transco’s revenues primarily associated with transportation rate increases effective March 1, 2025, including adjustments associated with the rate case, and 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;

•A $38 million increase in the 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, crude oil transportation and natural gas gathering volumes from a new well at Blind Faith in the Ballymore field and the absence of shut-ins for weather-related events at Gulfstar One in 2024;

•A $21 million increase primarily in natural gas gathering revenues due to the Discovery Acquisition n August 2024 (see Note 3 – Acquisitions and Divestitures) and volumes from the Shenandoah expansion project that went in-service in July 2025;

•A $10 million increase in Gulf Coast Storage’s revenues primarily associated with higher storage rates.

Other segment costs and expenses increased primarily due to:

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

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

•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 Gulf Coast region in 2025;

•Lower operating expenses and administrative costs including employee-related costs, primarily due to the absence of the impact of a 2024 change in a practice related to payroll timing.

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

•A $208 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;

•An $82 million increase in the 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 and 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, partially offset by shut-ins for maintenance activities at Devil’s Tower impacting the Taggart and Kodiak fields;

•A $67 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;

•A $32 million increase in Gulf Coast Storage’s revenues primarily associated with higher storage rates.

Commodity margins increased primarily due to the Discovery Acquisition.

Other segment costs and expenses increased primarily due to:

•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 the absence of a gain associated with MountainWest cash-out sales in 2024 and higher employee-related costs, partially offset by the absence of a 2024 change in a practice related to payroll timing and acquisition and transition costs related to the Gulf Coast Storage Acquisition in January 2024 (see Note 3 – Acquisitions and Divestitures);

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

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

•Higher project feasibility costs; partially offset by

•A net favorable change related to certain asset retirements in the 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.

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.

•A $7 million increase in revenues associated with reimbursable expenses, which is offset by similar changes in the charges reflected in Other segment costs and expenses;

•A $6 million increase in gathering revenues at Susquehanna Supply Hub primarily related to escalated rates;

•A $5 million increase in gathering revenues in the Utica Shale region primarily related to higher volumes at Cardinal;

•A $5 million increase in revenues at the Northeast JV primarily related to higher fractionation volumes, partially offset by lower processing volumes.

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). The increase was partially offset by lower employee-related costs, including 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.

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 $34 million increase in revenues at the Northeast JV primarily related to higher gathering, processing, and fractionation volumes, and higher gathering and processing rates;

•A $24 million increase in revenues associated with reimbursable expenses, which is offset by similar changes in the charges reflected in Other segment costs and expenses;

•A $12 million increase in gathering revenues in the Utica Shale region primarily related to higher volumes at Cardinal;

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

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). The increase was partially offset by lower employee-related costs, including 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 Blue Racer primarily due to higher volumes and annual rate escalations and at Laurel Mountain Midstream, LLC primarily due to higher commodity-based gathering rates. Additionally, Appalachia Midstream Investments increased primarily driven by escalated gathering rates and higher gathering 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.

West

(1) Included as a component of Commodity margins.

West Modified EBITDA increased primarily due to higher Service revenues, partially offset by higher Other segment costs and expenses.

•A $21 million increase in the Haynesville Shale region primarily due to higher gathering volumes including those resulting from the Saber Asset Purchase;

•A $19 million increase related to Louisiana Energy Gateway which was placed into service in third-quarter 2025;

•A $17 million increase in the DJ Basin region primarily due to higher gathering volumes associated with the Rimrock Asset Purchase; partially offset by

•A $22 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenue.

Other segment costs and expenses increased primarily due to the third-quarter 2025 $25 million write-off of certain compression assets in the DJ Basin region (see Note 8 – Fair Value Measurements and Guarantees). The increase was partially offset by lower employee-related costs, including the absence of the impact of a 2024 change in a practice related to payroll timing.

West Modified EBITDA increased primarily due to higher Service revenues and Commodity margins, partially offset by higher Other segment costs and expenses.

•A $48 million increase in the DJ Basin region primarily due to higher gathering volumes associated with the Rimrock Asset Purchase;

•A $37 million increase in the Haynesville Shale region primarily due to higher gathering volumes including those resulting from the Saber Asset Purchase;

•A $19 million increase related to Louisiana Energy Gateway which was placed into service in third-quarter 2025;

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

•A $51 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenue.

Commodity margins increased $23 million primarily due to $14 million higher margins from equity NGLs associated with higher net realized NGL sales prices and an $11 million increase in marketing margins from increased sales activities associated primarily with higher prices.

Other segment costs and expenses increased primarily due to the third-quarter 2025 $25 million write-off of certain compression assets in the DJ Basin region and higher operating expenses associated with the Rimrock Asset Purchase. The increase was partially offset by lower employee-related costs, including the absence of the impact of a 2024 change in a practice related to payroll timing.

Proportional Modified EBITDA of equity-method investments increased primarily due to higher volumes 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 instrumentsand higher Proportional Modified EBITDA of equity-method investments, partially offset by lower Commodity margins.

Commodity margins decreased $17 million primarily due to a $19 million decrease in natural gas marketing margins, including $36 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 $17 million of higher natural gas storage marketing margins primarily driven by favorable realized derivative gains.

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

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

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 $81 million primarily due to:

•A $68 million decrease in natural gas marketing margins, including $87 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 $19 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 $13 million decrease in NGL marketing margins including an unfavorable change in net realized gains and losses on sale of inventory in 2025 compared to 2024 driven by an unfavorable change in NGL prices.

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

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.

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 $55 million increase in Net realized product sales from our upstream operations primarily due to higher natural gas production volumes associated with Williams’ Wamsutter region production, including the Crowheart Acquisition. Third-quarter 2025 also benefited from higher net realized commodity prices for natural gas compared to third-quarter 2024; partially offset by

•A $20 million unfavorable change in other costs and expenses primarily related to upstream operations, including an increase from the Crowheart Acquisition in November 2024.

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

•A $132 million increase in Net realized product sales from upstream operations primarily due to higher production volumes and higher net realized commodity prices for natural gas, partially offset by lower net realized commodity prices for oil, associated with Williams’ Wamsutter region production, including the Crowheart Acquisition. The first nine months of 2025 also benefited from higher net realized commodity prices, partially offset by lower production volumes, associated with Williams’ South Mansfield production in the Haynesville Shale region;

•A $35 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 $60 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.