NORTHWEST PIPELINE LLC

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.

•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) – netreflects 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 (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.

•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) – netreflects 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.

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.

(1)Included as a component of Commodity margins.

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

•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.

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

•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.

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; 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.

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.

•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.

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

(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 $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.

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

•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

(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 Commodity margins.

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.

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 $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.

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:

•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.

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

•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.