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, 2026, compared to the three and nine months ended September 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.

•Higher revenues associated with the Momentum Acquisition (See Note 3 – Acquisitions and Divestitures) and expansion projects at the West and the Transmission, Power & Gulf segments;

•Higher power revenues primarily associated with Socrates South placed in service in late July 2026 at the Transmission, Power & Gulf segment;

•Increased Gulf Coast storage rates at the Transmission, Power & Gulf segment;

•Higher volumes from the Northeast JV at the Northeast G&P 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 at the Gas & NGL Marketing Services segment and the Momentum Acquisition;

•Higher equity NGL sales and commodity consideration revenues associated with equity NGL production activity primarily at the West segment;

•Higher product sales from upstream operations primarily related to higher prices 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 – Acquisitions and Divestitures).

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 (see Note 9 – Commodity Derivatives).

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

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

•Higher marketing activities related to NGLs at the Transmission, Power & Gulf and Gas & NGL Marketing Services segments and the Momentum Acquisition at the West segment;

•Higher 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 higher employee-related costs, operating costs associated with the Momentum Acquisition, and operating taxes.

Depreciation, depletion, and amortization expenses increased primarily related to the absence of adjustments associated with the rate case to Transco depreciation rates in 2025 as well as assets placed in service at the Transmission, Power & Gulf segment and the Momentum Acquisition, partially offset by the sale of the South Mansfield upstream interests.

General and administrative expenses increased due to higher employee-related costs, including incentive compensation, and transaction and acquisition-related costs at the Transmission, Power & Gulf and West segments.

Gain on sale of certain assets reflects a gain from the 2026 sale of certain gas gathering assets in the Permian Basin at the West segment (see Note 3 – Acquisitions and Divestitures).

Other operating (income) expense – net reflects the absence of the 2025 write-off of certain DJ Basin region assets in the West segment.

Interest expense was unfavorably impacted by 2025 and 2026 debt issuances including the debt retained in the Momentum Acquisition, partially offset by 2025 and 2026 debt retirements (see Note 6 – Debt and Banking Arrangements) 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 higher eligible capital expenditures at the regulated businesses.

Provision (benefit) for income taxes changed favorably primarily due to the absence of a provision associated with an increase in our estimate of the state deferred income tax rate in 2025, partially offset by 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.

The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to higher results at Pantheon.

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

•Increased Gulf Coast storage rates;

•Higher volumes from the Northeast JV;

•Higher power revenues primarily associated with Socrates South;

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

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 and the Momentum Acquisition;

•Higher equity NGL sales and commodity consideration revenues associated with equity NGL production activity primarily at the West segment; partially offset by

•Lower product sales from upstream operations primarily related to lower volumes from the sale of the South Mansfield upstream interests; partially offset by higher volumes and prices in the Wamsutter region.

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.

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

•Higher marketing activities related to NGLs at the Gas & NGL Marketing Services segment and the Momentum Acquisition;

•Higher 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 higher employee-related expenses, operating taxes, electricity and fuel, which is substantially offset by similar changes in Service revenues, and higher operating costs of the assets acquired in the Momentum Acquisition.

Depreciation, depletion, and amortization expenses increased primarily related to assets placed in service at the West and Transmission, Power & Gulf segments and the Momentum Acquisition, partially offset by the sale of the South Mansfield upstream interests.

General and administrative expenses increased due to higher employee-related costs, including incentive compensation, and transaction and acquisition-related costs at the Transmission, Power & Gulf and West segments.

Gain on sale of certain assets reflects gains from the 2026 sales of the South Mansfield upstream interests and certain gas gathering assets in the Permian Basin.

Other operating (income) expense – net reflects the absence of the 2025 write-off of certain DJ Basin region assets.

Equity earnings (losses)changed favorably primarily due to an increase at Appalachia Midstream Investments.

Other investing income (loss) – netreflects a gain from the 2026 sale of an equity-method investment in Brazos Permian II, LLC and higher interest income.

Interest expense was unfavorably impacted by 2025 and 2026 debt issuances including the debt retained in the Momentum Acquisition, 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 higher eligible capital expenditures at the regulated businesses.

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

The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to higher results at the Northeast JV and Pantheon.

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, partially offset by higher Other segment costs and expenses.

•A $53 million increase in power revenues primarily associated with Socrates South placed in service in late July 2026, as well as revenues associated with reimbursable fuel expenses (which are substantially offset by similar changes reflected in Other segment costs and expenses);

•A $21 million increase in Gulf Coast Storage’s revenues primarily associated with higher storage rates;

•A $7 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 $7 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 increased primarily due to:

•Higher operating expenses and administrative costs including higher transaction expenses, employee-related costs, and corporate allocations, as well as higher fuel expenses (substantially offset by higher Service revenues discussed above);

•An unfavorable change related to certain asset retirements in the Gulf Coast region; partially offset by

•A favorable change in equity AFUDC primarily from higher eligible capital expenditures at Transco and Driftwood Pipeline’s Line 200.

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

•A $77 million increase in Transco’s revenues primarily associated with expansion projects placed in service, as well as higher park and loan services and revenues associated with reimbursable expenses (which are substantially offset by similar changes reflected in Other segment costs and expenses), partially offset by decreases in commodity revenues;

•A $62 million increase in Gulf Coast Storage’s revenues primarily associated with higher storage rates and higher park and loan services;

•A $58 million increase in power revenues primarily associated with Socrates South, as well as revenues associated with reimbursable fuel expenses (which are substantially offset by similar changes reflected in Other segment costs and expenses);

•A $29 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 $19 million increase in NWP’s revenues primarily due to transportation rate increases;

•A $19 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;

•A $17 million increase in MountainWest’s revenues primarily due to the Overthrust Westbound Compression expansion project;

•A $16 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 and lower revenues associated with reimbursable expenses (which are substantially offset by similar changes reflected in Other segment costs and expenses) from the Kodiak field.

Other segment costs and expenses increased primarily due to:

•Higher operating expenses and administrative costs including higher transaction expenses, employee-related costs, and corporate allocations, as well as higher net electricity and fuel expenses (substantially offset by higher Service revenues discussed above);

•An unfavorable change related to certain asset retirements in the Gulf Coast region; partially offset by

•A favorable change in equity AFUDC primarily from higher eligible capital expenditures at Transco and Driftwood Pipeline’s Line 200.

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 $22 million increase in revenues at the Northeast JV primarily related to higher gathering, processing, transportation, and fractionation volumes;

•A $9 million increase in gathering revenues at Susquehanna Supply Hub primarily related to increased gathering volumes and escalated gathering rates.

Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments primarily driven by 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 lower Commodity margins.

•A $60 million increase in revenues at the Northeast JV primarily related to higher gathering, processing, transportation, and fractionation volumes;

•A $21 million increase in revenues associated with reimbursable expenses, which is substantially offset by similar changes reflected in Other segment costs and expenses; partially offset by

•A $4 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 due higher electricity and fuel (substantially offset by higher Service revenues), partially offset by lower maintenance expenses.

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

(1) Included as a component of Commodity margins.

West Modified EBITDA increased primarily due to Gain on sale of certain assets and higher Service revenues, partially offset by higher Other segment costs and expenses.

•An $87 million increase in the Haynesville Shale region primarily due to the Momentum Acquisition (see Note 3 – Acquisitions and Divestitures) in the third quarter of 2026 and contributions from Louisiana Energy Gateway which was placed into service in the third quarter of 2025; partially offset by

•An $11 million decrease in the Mid-Continent and Permian basin regions due to the sale of certain gas gathering assets in February 2026 and August 2026, respectively.

Other segment costs and expenses increased primarily due to higher operating expenses and acquisition-related costs associated with the Momentum Acquisition, partially offset by the absence of 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).

Gain on sale of certain assets reflects the gain from the sale of certain gas gathering assets in the Permian basin in the third quarter of 2026.

West Modified EBITDA increased primarily due to higher Service revenuesand Gain on sale of certain assets, partially offset byhigher Other segment costs and expenses.

•A $188 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, the Momentum Acquisition in the third quarter of 2026, as well as higher gathering volumes including those from the acquisition of Saber Midstream, LLC in June 2025;

•A $20 million increase in the Piceance region primary due to higher commodity-price driven processing rates and higher volumes; partially offset by

•A $26 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenue and lower gathering volumes due to decreased producer activity;

•A $16 million decrease in the Mid-Continent region due to the sale of certain gas gathering assets in February 2026.

Other segment costs and expenses increased primarily due to higher operating expenses and acquisition-related costs associated with the Momentum Acquisition, as well as higher operating taxes associated with Louisiana Energy Gateway, partially offset by the absence of the third-quarter 2025 $25 million write-off of certain compression assets in the DJ Basin region.

Gain on sale of certain assets reflects the gain from the sale of certain gas gathering assets in the Permian basin in the third quarter of 2026.

Gas & NGL Marketing Services

(1) Included as a component of Commodity margins.

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

Commodity margins increased $3 million primarily due to a $6 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.

Gas & NGL Marketing Services Modified EBITDA increased primarily due to higher Commodity marginsand 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 $88 million primarily due to:

•A $68 million increase in natural gas marketing margins, including $62 million of higher natural gas transportation capacity marketing margins primarily driven by favorable net realized pricing spreads;

•A $20 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.

Other

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

Modified EBITDA from upstream operations, corporate, and other business activities decreased primarily due to lower Net realized product sales, an unfavorable change in Net unrealized gain (loss) from derivative instruments, and higher Other costs and expenses, partially offset by higher Service revenues.

Service revenues increased primarily due to lease revenues from certain corporate office properties.

Net realized product sales from our upstream operations decreased primarily due to:

•A $30 million decrease driven by the January 2026 sale of certain South Mansfield upstream interests; partially offset by

•A $7 million increase at the Wamsutter region due to $11 million associated with higher production volumes driven by new wells, partially offset by a $4 million decrease driven by lower net realized natural gas prices.

Net unrealized gain (loss) from derivative instruments changed from 2025 primarily due to a change in forward commodity prices relative to hedge positions in 2026 compared to 2025.

Other costs and expenses increased primarily due to higher employee-related incentive compensation and higher Wamsutter upstream operating expenses, partially offset by the absence of upstream operating expenses associated with the disposed South Mansfield upstream interests and higher income 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 increased primarily due to the Gain on sale of certain assets driven by the January 2026 sale of certain South Mansfield upstream interests and higher Service revenues, partially offset by lower Net realized product sales, an unfavorable change in Net unrealized gain (loss) from derivative instruments, and higher Other costs and expenses.

Service revenues increased primarily due to lease revenues from certain corporate office properties.

Net realized product sales from our upstream operations decreased primarily due to:

•A $73 million decrease driven by the January 2026 sale of certain South Mansfield upstream interests; partially offset by

•A $14 million increase at the Wamsutter region due to $47 million associated with higher production volumes driven by new wells, partially offset by a $33 million decrease driven by lower net realized natural gas prices.

Net unrealized gain (loss) from derivative instruments changed from 2025 primarily due to a change in forward commodity prices relative to hedge positions in 2026 compared to 2025.

Other costs and expenses increased primarily due to higher Wamsutter upstream operating expenses and higher employee-related incentive compensation, partially offset by the absence of upstream operating expenses associated with the disposed South Mansfield upstream interests and higher income associated with regulatory assets related to the effects of deferred taxes on equity funds used during construction.

Gain on sale of certain assets relates to the January 2026 sale of the South Mansfield upstream interests.