Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

We are an energy company committed to being the leader in providing infrastructure that safely delivers natural gas products to reliably fuel the clean energy economy. Our operations are located in the United States.

Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high-quality, low-cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established primarily through the FERC’s ratemaking process, but we also may negotiate rates with our customers pursuant to the terms of our tariffs and FERC policy. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing, treating, compression and storage, NGL fractionation, transportation and storage, crude oil production handling and transportation, as well as marketing services for NGL, crude oil, and natural gas.

Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, West, and Gas & NGL Marketing Services. All remaining business activities, including our upstream operations and corporate activities, are included in Other. Our reportable segments are comprised of the following business activities:

*•*Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco, Northwest Pipeline, and MountainWest, and their related natural gas storage facilities, as well as natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One, a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery (see Note 11 – Subsequent Events). Transmission & Gulf of Mexico also includes natural gas storage facilities and pipelines providing services in north Texas, and also in Louisiana and Mississippi related to the January 2024 Gulf Coast Storage Acquisition (see Note 3 – Acquisitions and Divestitures).

Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in Northeast JV which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 50 percent equity-method investment in Blue Racer, and Appalachia Midstream Investments.
West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of east Texas and northwest Louisiana, the Mid-Continent region which includes the Anadarko and Permian basins, and the DJ Basin of Colorado which includes RMM, a former 50 percent equity-method investment in which we acquired the remaining ownership interest in November 2023 (see Note 3 – Acquisitions and Divestitures). This segment also includes our NGL storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in OPPL.

Management’s Discussion and Analysis (Continued)

Gas & NGL Marketing Services is comprised of our NGL and natural gas marketing and trading operations, which includes risk management and transactions related to the storage and transportation of natural gas and NGLs on strategically positioned assets.

Unless indicated otherwise, the following discussion and analysis of results of operations and financial condition and liquidity relates to our current continuing operations and should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2023 dated February 21, 2024.

Dividends

In June 2024, we paid a regular quarterly dividend of $0.4750 per share.

Overview of Six Months Ended June 30, 2024

Net income (loss) attributable to The Williams Companies, Inc. for the six months ended June 30, 2024, decreased $354 million compared to the six months ended June 30, 2023. Further discussion of our results is found in this report in the Results of Operations.

Recent Developments

Expansion Project Updates

Transmission & Gulf of Mexico

Regional Energy Access

In January 2023, we received approval from the FERC for the project to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in northeastern Pennsylvania to multiple delivery points in Pennsylvania, New Jersey, and Maryland. We placed approximately half of the project into service in the fourth quarter of 2023 and placed the remainder of the project into service in August 2024. The project increased capacity by 829 Mdth/d.

On July 30, 2024, the D.C. Circuit Court of Appeals granted petitions for review of the FERC orders approving the project, vacating such orders and remanding the matter to the FERC for appropriate action. The court’s decision will not be effective until the court has issued its mandate (which is not expected to occur until mid-September 2024 at the earliest), so the decision will not have an immediate impact on the project or the service being rendered through the project capacity. We will take the necessary legal and regulatory actions to ensure that the project capacity continues to be available to serve the needs of our customers without interruption.

Acquisitions and Divestitures

Discovery Acquisition

As of December 31, 2023, we owned a 60 percent interest in Discovery which we accounted for as an equity-method investment. On August 1, 2024, we closed on the acquisition of the remaining 40 percent interest in Discovery, along with certain other assets, for $170 million, subject to working capital and post-closing adjustments. As a result of acquiring this additional interest, we obtained control and will consolidate Discovery. The purpose of this acquisition was to expand our gathering, processing, and transportation footprint in the Gulf of Mexico region. Assets acquired, acquisition-related costs incurred, and results of operations realized will be included within our Transmission & Gulf of Mexico segment (see Note 11 – Subsequent Events).

Management’s Discussion and Analysis (Continued)

Sale of Aux Sable Interest

Also on August 1, 2024, we completed the sale of our equity-method investments in Aux Sable for total consideration of $160 million. As a result of this sale, we expect to record a gain in the third quarter of 2024 in our Northeast G&P segment (see Note 11 – Subsequent Events).

Gulf Coast Storage Acquisition

On January 3, 2024, we closed on the acquisition of 100 percent of a strategic portfolio of natural gas storage facilities and pipelines, located in Louisiana and Mississippi, from Hartree Partners LP for $1.95 billion. The purpose of this acquisition, which is reported in the Transmission & Gulf of Mexico segment, was to expand our natural gas storage footprint in the Gulf Coast region. The Gulf Coast Storage Acquisition was funded with cash on hand and $100 million of deferred consideration (see Note 3 – Acquisitions and Divestitures).

Company Outlook

Our strategy is to provide a large-scale, reliable, and clean energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. We accomplish this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. We continue to maintain a strong commitment to safety, environmental stewardship including seeking opportunities for renewable energy ventures, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe, reliable, clean energy services to our customers and an attractive return to our shareholders. Our business plan for 2024 includes a continued focus on earnings and cash flow growth.

In 2024, our operating results are expected to benefit from the recent Gulf Coast Storage and DJ Basin acquisitions. We also anticipate increases resulting from Transmission & Gulf of Mexico expansion projects, including the Regional Energy Access project, and annual inflation-based rate increases across our gathering and processing business. These increases are partially offset by lower expected Gas & NGL Marketing Services results, the absence of realized hedge gains captured in 2023 in the West, and a decrease in expected volumes primarily in the Appalachian and Haynesville basins associated with a lower expected commodity price environment.

We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of safe, clean, and reliable energy infrastructure assets that continue to serve key growth markets and supply basins in the United States. Our growth capital and investment expenditures in 2024 are expected to range from $1.45 billion to $1.75 billion, excluding acquisitions. Growth capital spending in 2024 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting growth in the Haynesville Basin, and projects supporting the Northeast G&P business. We also expect to invest capital in our Other business ventures. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that reduce emissions, and meet legal, regulatory, and/or contractual commitments.

Potential risks and obstacles that could impact the execution of our plan include:

A global recession, which could result in downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;
Opposition to, and regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;
Counterparty credit and performance risk;

Management’s Discussion and Analysis (Continued)

Unexpected significant increases in capital expenditures or delays in capital project execution, including increases from inflation or delays caused by supply chain disruptions;
Unexpected changes in customer drilling and production activities, which could negatively impact gathering and processing volumes;
Lower than anticipated demand for natural gas and natural gas products which could result in lower-than-expected volumes, energy commodity prices, and margins;
General economic, financial markets, or industry downturns, including increased inflation and interest rates;
Physical damages to facilities, including damage to offshore facilities by weather-related events;
Other risks set forth under Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2023, as filed with the SEC on February 21, 2024, as may be supplemented by disclosure in Part II, Item 1A. Risk Factors in subsequent Quarterly Reports on Form 10-Q.

Expansion Projects

Our ongoing major expansion projects include the following:

Transmission & Gulf of Mexico

Deepwater Shenandoah Project

In June 2021, we reached an agreement with two third-parties to provide offshore natural gas gathering and transportation services as well as onshore natural gas processing services. The project expands our existing Gulf of Mexico offshore infrastructure via a 5-mile offshore lateral pipeline from the Shenandoah platform to Discovery’s existing Keathley Canyon Connector pipeline, adds onshore processing facilities at Larose, Louisiana to handle the expected rich Shenandoah production, and the natural gas liquids will be fractionated and marketed at Discovery’s Paradis plant in Louisiana. We plan to place the project into service in the second quarter of 2025.

Deepwater Whale Project

In August 2021, we reached an agreement with two third-parties to provide offshore natural gas gathering and crude oil transportation services as well as onshore natural gas processing services. The project expands our existing Western Gulf of Mexico offshore infrastructure via a 26-mile gas lateral pipeline from the Whale platform to the existing Perdido gas pipeline and adds a new 125-mile oil pipeline from the Whale platform to our existing junction platform. We plan to place the project into service in the fourth quarter of 2024.

Southside Reliability Enhancement

In July 2023, we received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Virginia and North Carolina to delivery points in North Carolina. We plan to place the project into service as early as the fourth quarter of 2024, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 423 Mdth/d.

Texas to Louisiana Energy Pathway

In January 2024, we received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide firm transportation capacity from receipt points in south Texas to delivery points in Texas and Louisiana. We plan to place the project into service as early as the first quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to

Management’s Discussion and Analysis (Continued)

provide 364 Mdth/d of new firm transportation service through a combination of increasing capacity, converting interruptible capacity to firm, and utilizing existing capacity.

Southeast Energy Connector

In November 2023, we received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Mississippi and Alabama to a delivery point in Alabama. We plan to place the project into service in the second quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 150 Mdth/d.

Commonwealth Energy Connector

In November 2023, we received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity in Virginia. We plan to place the project into service as early as the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 105 Mdth/d.

Alabama Georgia Connector

In March 2024, we received approval from the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from our Station 85 pooling point in Alabama to customers in Georgia. We plan to place the project into service as early as the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 64 Mdth/d.

Southeast Supply Enhancement

We plan to file an application with the FERC as early as the third quarter of 2024 for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Virginia to delivery points in Virginia, North Carolina, South Carolina, Georgia, and Alabama. We plan to place the project into service as early as the fourth quarter of 2027, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 1,592 Mdth/d.

Gillis West

We plan to file our prior notice application for the project with the FERC as early as the fourth quarter of 2024, which involves an expansion of Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in Louisiana to delivery points in Texas. We plan to place the project into service as early as the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 115 Mdth/d.

Overthrust Westbound Compression Expansion

In November 2023, we filed an application with the FERC for the project, which involves an expansion of MountainWest’s existing natural gas transmission system to provide incremental firm transportation capacity from multiple receipt points in Wamsutter, Wyoming to a delivery point in Opal, Wyoming. We plan to place the project into service as early as the fourth quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 325 Mdth/d.

Management’s Discussion and Analysis (Continued)

Northeast G&P

Cardinal Gathering Expansion

We have an agreement in place with a third party to facilitate natural gas production growth in the Utica Shale region. We plan to construct approximately 8 miles of gathering pipeline and associated incremental compression. The system, once constructed, will add incremental capacity of 125 MMcf/d and will provide natural gas gathering services to the third party. The project is expected to go into service in the third quarter of 2025.

West

Louisiana Energy Gateway

In August 2024, we began construction activities on new natural gas gathering assets which are expected to gather 1.8 Bcf/d of natural gas produced in the Haynesville Shale basin for delivery to premium markets, including Transco, industrial markets, and growing LNG export demand along the Gulf Coast. This project is expected to go into service in the second half of 2025.

Haynesville Gathering Expansion

In February 2023, we announced our agreement with a third party to facilitate natural gas production growth in the Haynesville basin. We plan to construct a greenfield gathering system in support of the third party’s 26,000-acre dedication. The system, once constructed, will provide natural gas gathering services to the third party. The third party has also agreed to a long-term capacity commitment on our Louisiana Energy Gateway project. This project is expected to go into service in the second quarter of 2025.

Management’s Discussion and Analysis (Continued)

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three and six months ended June 30, 2024, compared to the three and six months ended June 30, 2023, and should be read in conjunction with the results of operations by segment, as discussed in further detail following this consolidated overview discussion.



	Three Months Ended June 30,				Change*			Six Months Ended June 30,				Change*
	2024		2023		$	%		2024		2023		$	%
	(Dollars in millions)							(Dollars in millions)
Revenues:
Service revenues	$	1,837	$	1,748	+89	+5	%	$	3,742	$	3,442	+300	+9	%

Product sales and service revenues – commodity consideration	628		620		+8	+1	%	1,503		1,501		+2	—	%
Net gain (loss) from commodity derivatives	(129)		115		-244	NM		(138)		621		-759	NM
Total revenues	2,336		2,483					5,107		5,564
Costs and expenses:
Product costs and net processing commodity expenses	441		465		+24	+5	%	972		1,072		+100	+9	%

Operating and maintenance expenses	522		481		-41	-9	%	1,033		944		-89	-9	%
Depreciation and amortization expenses	540		515		-25	-5	%	1,088		1,021		-67	-7	%
Selling, general, and administrative expenses	164		161		-3	-2	%	350		337		-13	-4	%




Other (income) expense – net	(27)		(9)		+18	+200	%	(44)		(40)		+4	+10	%
Total costs and expenses	1,640		1,613					3,399		3,334
Operating income (loss)	696		870					1,708		2,230
Equity earnings (losses)	147		160		-13	-8	%	284		307		-23	-7	%

Other investing income (loss) – net	18		13		+5	+38	%	42		21		+21	+100	%
Interest expense	(339)		(306)		-33	-11	%	(688)		(600)		-88	-15	%

Other income (expense) – net	33		19		+14	+74	%	64		39		+25	+64	%
Income (loss) before income taxes	555		756					1,410		1,997
Less: Provision (benefit) for income taxes	129		175		+46	+26	%	322		459		+137	+30	%
Income (loss) from continuing operations	426		581					1,088		1,538
Income (loss) from discontinued operations	—		(87)		+87	+100	%	—		(87)		+87	+100	%
Net income (loss)	426		494					1,088		1,451
Less: Net income attributable to noncontrolling interests	25		34		+9	+26	%	55		64		+9	+14	%
Net income (loss) attributable to The Williams Companies, Inc.	$	401	$	460	-59	-13	%	$	1,033	$	1,387	-354	-26	%

- = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.

Management’s Discussion and Analysis (Continued)

Three months ended June 30, 2024 vs. three months ended June 30, 2023

Service revenues increased primarily due to higher volumes from the November 2023 DJ Basin Acquisitions at our West segment and the January 2024 Gulf Coast Storage acquisition at our Transmission & Gulf of Mexico segment (see Note 3 – Acquisitions and Divestitures), and higher revenues associated with an expansion project at our Transmission & Gulf of Mexico segment; partially offset by lower gathering volumes at our Northeast G&P and West Segments.

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 our processing plants for our reportable segments comprise our Commodity Margins. Service revenues - commodity consideration represent payments we receive 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 our upstream operations comprise Net realized product sales.

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

Higher net natural gas marketing sales and purchases volumes, partially offset by lower net prices;
Higher NGL marketing sales primarily due to higher non-ethane prices, partially offset by lower ethane volumes and prices; partially offset by
Lower system management gas sales.

As we are acting as agent for natural gas marketing customers, our natural gas marketing product sales are presented net of the related costs of those activities within our 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 our Gas & NGL Marketing Services and West segments, and at Other (see Note 8 – Commodity Derivatives).

We experience 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 system management gas purchases; partially offset by
Higher non-ethane prices, partially offset by lower ethane volumes for our NGL marketing activities.

Operating and maintenance expenses increased primarily due to operating costs of the assets acquired at our West and Transmission & Gulf of Mexico segments.

Depreciation and amortization expenses increased primarily related to assets acquired at our West and Transmission & Gulf of Mexico segments.

Management’s Discussion and Analysis (Continued)

Equity earnings (losses) changed unfavorably primarily due to the consolidation of RMM following our acquisition of the remaining ownership interest in November 2023 and a decrease at Blue Racer, partially offset by favorable results at OPPL.

The increase in Interest expense was primarily due to our 2023 and 2024 debt issuances, and imputed interest on deferred consideration obligations related to our DJ Basin and Gulf Coast Storage acquisitions, partially offset by 2023 and 2024 debt retirements (see Note 6 – Debt and Banking Arrangements).

Provision (benefit) for income taxes changed favorably primarily due to lower 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.

Income (loss) from discontinued operations in 2023 includes a pre-tax charge of $115 million to increase the accrued liability associated with our Alaska refinery contamination litigation, partially offset by the related income tax effect.

Six months ended June 30, 2024 vs. six months ended June 30, 2023

Service revenues increased primarily due to higher volumes from the January 2024 Gulf Coast Storage and February 2023 MountainWest acquisitions at our Transmission & Gulf of Mexico segment and the November 2023 DJ Basin Acquisitions at our West segment, and higher revenues associated with an expansion project at our Transmission & Gulf of Mexico segment.

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

Higher net natural gas marketing sales primarily due to higher sales and purchases volumes substantially offset by lower net prices and higher storage costs;

*•*Higher product sales from our upstream operations primarily due to higher production volumes, partially offset by lower commodity prices. These sales are partially offset by

Lower system management gas sales;
Lower NGL marketing sales primarily due to lower ethane volumes, partially offset by higher non-ethane prices.

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

Lower shrink gas purchases associated with our equity NGL production activities due to lower natural gas prices and volumes;
Lower system management gas purchases; and
Lower NGL marketing purchases due to lower ethane volumes, partially offset by higher non-ethane prices.

Operating and maintenance expenses increased primarily due to operating costs of the assets acquired at our West and Transmission & Gulf of Mexico segments, as well as an unfavorable change in our net imbalance liability due to changes in pricing.

Depreciation and amortization expenses increased primarily related to the assets acquired at our West and Transmission & Gulf of Mexico segments.

Management’s Discussion and Analysis (Continued)

The increase in Interest expense was primarily due to our 2023 and 2024 debt issuances, and imputed interest on deferred consideration obligations related to our DJ Basin and Gulf Coast Storage Acquisitions, partially offset by 2023 and 2024 debt retirements (see Note 6 – Debt and Banking Arrangements).

The favorable change in Other income (expense) – net below Operating income (loss) includes an increase in equity allowance for funds used during construction (equity AFUDC) at our Transmission & Gulf of Mexico segment.

Period-Over-Period Operating Results – Segments

We evaluate segment operating performance based upon Modified EBITDA. Note 10 – Segment Disclosures includes a reconciliation of this non-GAAP measure to Net income (loss). 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 our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.

Transmission & Gulf of Mexico



	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
	(Millions)
Service revenues	$	1,023	$	956	$	2,072	$	1,896


Product sales and service revenues – commodity consideration (1)	45		85		115		152


Net realized gain (loss) from commodity derivatives (1)	—		1		—		1



Segment revenues	1,068		1,042		2,187		2,049



Product costs and net processing commodity expenses (1)	(40)		(78)		(101)		(135)
Other segment costs and expenses	(269)		(281)		(544)		(569)




Proportional Modified EBITDA of equity-method investments	49		48		95		101
Transmission & Gulf of Mexico Modified EBITDA	$	808	$	731	$	1,637	$	1,446

Commodity margins	$	5	$	8	$	14	$	18

(1)Included as a component of Commodity margins.

Management’s Discussion and Analysis (Continued)

Three months ended June 30, 2024 vs. three months ended June 30, 2023

Transmission & Gulf of Mexico Modified EBITDA increased primarily due to higher Service revenues.

Service revenues increased primarily due to:

*•*A $58 million increase due to the acquisition of Gulf Coast Storage assets in January 2024 primarily in storage revenues (see Note 3 – Acquisitions and Divestitures);

A $20 million increase in Transco’s revenues associated with the Regional Energy Access expansion project placed partially in-service in the fourth quarter of 2023; partially offset by
A $12 million decrease due to the sale of certain liquids pipelines in the Gulf Coast region in September 2023 primarily in transportation revenues (see Note 3 – Acquisitions and Divestitures).

Other segment costs and expenses decreased primarily due to:

*•*A favorable change in equity AFUDC primarily as a result of increased capital expenditures at Transco;

A favorable change in the deferral of ARO-related depreciation at Transco; partially offset by
Higher operating expenses and administrative costs including higher operating, acquisition and transition costs related to our Gulf Coast Storage Acquisition and higher costs related to timing and scope of general maintenance activities; substantially offset by significantly lower acquisition and transition costs related to our MountainWest Acquisition (see Note 3 – Acquisitions and Divestitures); a gain associated with MountainWest cash-out sales; and the sale of certain liquids pipelines in the Gulf Coast region.

Six months ended June 30, 2024 vs. six months ended June 30, 2023

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

Service revenues increased primarily due to:

*•*A $108 million increase due to the acquisition of Gulf Coast Storage assets primarily in storage revenues;

A $40 million increase in Transco’s revenues associated with the Regional Energy Access expansion project;
A $37 million increase in transportation and storage revenues at MountainWest primarily due to the acquisition in February 2023;
A $10 million increase in NorTex’s revenues primarily associated with higher storage rates; partially offset by
A $25 million decrease due to the sale of certain liquids pipelines in the Gulf Coast region primarily in transportation revenues.

Other segment costs and expenses decreased primarily due to:

*•*A favorable change in equity AFUDC primarily as a result of increased capital expenditures at Transco;

A favorable change in the deferral of ARO-related depreciation at Transco; partially offset by

Management’s Discussion and Analysis (Continued)

Higher operating expenses and administrative costs including higher operating, acquisition and transition costs related to our Gulf Coast Storage Acquisition and higher operating and administrative expenses related to our MountainWest Acquisition; substantially offset by significantly lower acquisition and transition costs related to our MountainWest Acquisition; a gain associated with MountainWest cash-out sales; and the sale of certain liquids pipelines in the Gulf Coast region.

Northeast G&P



	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
	(Millions)
Service revenues	$	465	$	489	$	944	$	943
Product sales and service revenues – commodity consideration (1)	18		25		48		80
Segment revenues	483		514		992		1,023

Product costs and net processing commodity expenses (1)	(18)		(26)		(37)		(76)
Other segment costs and expenses	(137)		(132)		(280)		(264)

Proportional Modified EBITDA of equity-method investments	153		159		310		302
Northeast G&P Modified EBITDA	$	481	$	515	$	985	$	985

Commodity margins	$	—	$	(1)	$	11	$	4

(1)Included as a component of Commodity margins.

Three months ended June 30, 2024 vs. three months ended June 30, 2023

Northeast G&P Modified EBITDA decreased primarily due to lower Service revenues and lower Proportional Modified EBITDA of equity-method investments.

Service revenues decreased primarily due to:

*•*A $24 million decrease in revenues in the Utica Shale region primarily related to the timing of recognition of the 2023 cost of service rate increase at Cardinal associated with the annual redetermination of those rates as well as lower volumes at Flint and Cardinal;

*•*An $8 million decrease in gathering revenues at Susquehanna Supply Hub primarily related to lower volumes partially offset by escalated rates.

Proportional Modified EBITDA of equity-method investments decreased at Blue Racer primarily driven by lower gathering volumes. Additionally, Appalachia Midstream Investments decreased primarily driven by lower volumes significantly offset by higher gathering rates at the Bradford Supply Hub.

Six months ended June 30, 2024 vs. six months ended June 30, 2023

Northeast G&P Modified EBITDA was consistent with the prior year primarily due to higher Other segment costs and expenses, partially offset by higher Proportional Modified EBITDA of equity-method investments.

Service revenues were consistent with the prior year primarily due to:

*•*An $11 million increase in gathering revenues at Susquehanna Supply Hub primarily related to escalated rates partially offset by lower volumes;

Management’s Discussion and Analysis (Continued)

*•*An $8 million increase in joint venture operating fees primarily related to us assuming operatorship of Blue Racer effective January 1, 2024 (which is significantly offset by higher Other segment costs and expenses discussed below); offset by

A $15 million decrease in revenues in the Utica Shale region primarily related to lower volumes at Flint and Cardinal;

*•*An $11 million decrease in revenues at the Northeast JV primarily related to lower transportation & fractionation, processing, and gathering volumes, partially offset by higher processing and transportation & fractionation rates.

Other segment costs and expenses increased primarily due to higher employee-related costs as well as increased corporate allocations of support costs related to us assuming operatorship of Blue Racer effective January 1, 2024 (substantially offset by higher Service revenues discussed above).

Proportional Modified EBITDA of equity-method investments increased at Aux Sable Liquid Products LP primarily due to the terms of the new product marketing agreement. Additionally, Appalachia Midstream Investments increased primarily driven by higher gathering rates partially offset by lower volumes at the Bradford Supply Hub. The increase was partially offset by a decrease at Blue Racer primarily driven by lower gathering volumes offset by higher processing volumes.

West



	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
	(Millions)
Service revenues	$	407	$	358	$	844	$	714
Product sales and service revenues – commodity consideration (1)	209		109		473		217

Net realized gain (loss) from commodity derivatives relating to service revenues	7		29		10		68
Net realized gain (loss) from commodity derivatives relating to product sales (1)	(2)		4		(5)		4
Net realized gain (loss) from commodity derivatives	5		33		5		72

Segment revenues	621		500		1,322		1,003

Product costs and net processing commodity expenses (1)	(177)		(95)		(426)		(227)
Other segment costs and expenses	(162)		(136)		(312)		(236)


Proportional Modified EBITDA of equity-method investments	36		43		61		76
West Modified EBITDA	$	318	$	312	$	645	$	616

Commodity margins	$	30	$	18	$	42	$	(6)

(1) Included as a component of Commodity margins.

Management’s Discussion and Analysis (Continued)

Three months ended June 30, 2024 vs. three months ended June 30, 2023

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

Service revenues increased primarily due to:

*•*A $69 million increase in the DJ Basin region associated with the DJ Basin Acquisitions in November 2023 (see Note 3 – Acquisitions and Divestitures);

An $8 million increase in our NGL operations associated with higher fractionation and transportation revenue both due to higher volumes; partially offset by
A $17 million decrease in the Haynesville Shale region primarily associated with lower gathering volumes from decreased producer activity;
A $9 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenues 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 our natural gas hedge positions.

Commodity margins increased $12 million primarily due to a $12 million increase in marketing margins and a $6 million increase from other sales activities both associated primarily with the Cureton Acquisition, partially offset by a $6 million decrease from our equity NGLs primarily due to an unfavorable change in net realized commodity pricing.

Other segment costs and expenses increased primarily due to higher operating expenses including those resulting from the DJ Basin Acquisitions.

Proportional Modified EBITDA of equity-method investments decreased primarily due to lower proportional results as RMM was consolidated as of November 30, 2023, partially offset by higher volumes at OPPL.

Six months ended June 30, 2024 vs. six months ended June 30, 2023

West Modified EBITDA increased primarily due higher Service revenues and 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.

Service revenues increased primarily due to:

A $141 million increase in the DJ Basin region associated with the DJ Basin Acquisitions in November 2023 (see Note 3 – Acquisitions and Divestitures);
A $20 million increase in our 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 $17 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; partially offset by
An $18 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenues as well as lower gathering volumes;

Management’s Discussion and Analysis (Continued)

A $16 million decrease in the Haynesville Shale region primarily due to lower gathering volumes from decreased producer activity;
A $14 million decrease in the Barnett Shale region primarily due to lower gathering rates driven by unfavorable commodity pricing.

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

Commodity margins increased $48 million primarily due to a $24 million increase from our equity NGLs due to a favorable change in net realized commodity pricing primarily for shrink gas purchases and a $13 million increase in marketing margins as well as an $11 million increase from other sales activities, both associated primarily with the Cureton Acquisition.

Other segment costs and expenses increased primarily due to higher operating and employee-related expenses including those resulting from the DJ Basin Acquisitions, the absence of favorable contract settlements in first-quarter 2023, and an unfavorable change in our net imbalance liability due to changes in pricing.

Gas & NGL Marketing Services



	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
	(Millions)
Service revenues	$	—	$	—	$	—	$	1
Product sales (1)	423		427		1,010		1,102

Net realized gain (loss) from commodity derivative instruments (1)	(33)		(45)		48		72
Net unrealized gain (loss) from commodity derivative instruments	(99)		123		(197)		461
Net gain (loss) from commodity derivatives	(132)		78		(149)		533

Segment revenues	291		505		861		1,636
Net unrealized gain (loss) from commodity derivative instruments within Net processing commodity expenses	(7)		(29)		(4)		(34)
Product costs (1)	(387)		(384)		(819)		(911)
Other segment costs and expenses	(23)		(24)		(63)		(56)
Gas & NGL Marketing Services Modified EBITDA	$	(126)	$	68	$	(25)	$	635

Commodity margins	$	3	$	(2)	$	239	$	263

(1) Included as a component of Commodity margins.

Three months ended June 30, 2024 vs. three months ended June 30, 2023

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

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

Management’s Discussion and Analysis (Continued)

change from 2023 is primarily due to a change in forward commodity prices relative to our hedge positions in 2024 compared to 2023.

Six months ended June 30, 2024 vs. six months ended June 30, 2023

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 $24 million primarily due to a $29 million decrease in our natural gas marketing margins including $18 million of lower natural gas storage marketing margins primarily driven by lower withdrawals from warmer winter weather in first quarter 2024 compared to 2023 and a less favorable change in realized derivative gains, partially offset by a favorable change of $12 million in lower cost or net realizable value inventory adjustment. The decrease in our natural gas marketing margins also includes $11 million of lower natural gas transportation capacity marketing margins due to less favorable net realized pricing spreads.

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

Other



	Three Months Ended June 30,				Six Months Ended June 30,
	2024		2023		2024		2023
	(Millions)
Service revenues	$	4	$	5	$	8	$	8
Product sales (1)	86		83		194		185

Net realized gain (loss) from derivative instruments (1)	23		14		28		32
Net unrealized gain (loss) from derivative instruments	(25)		(11)		(22)		(17)
Net gain (loss) from commodity derivatives	(2)		3		6		15

Segment revenues	88		91		208		208

Other segment costs and expenses	(41)		(49)		(85)		(92)

Proportional Modified EBITDA of equity-method investments	—		(1)		—		(1)
Modified EBITDA of other business activities	$	47	$	41	$	123	$	115

Net realized product sales	$	109	$	97	$	222	$	217

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

Three months ended June 30, 2024 vs. three months ended June 30, 2023

Modified EBITDA of other business activities increased primarily due to:

A $12 million increase in Net realized product sales from our upstream operations primarily due to higher production volumes;
An $8 million favorable Other segment costs and expenses related to lower corporate costs; partially offset by

Management’s Discussion and Analysis (Continued)

*•*A $14 million unfavorable change in Net unrealized gain (loss) from derivative instruments due to changes in forward commodity prices relative to our upstream hedge positions in 2024 compared to 2023.

Six months ended June 30, 2024 vs. six months ended June 30, 2023

Modified EBITDA of other business activities increased primarily due to:

*•*A $5 million increase in Net realized product sales from our upstream operations primarily due to higher production volumes, partially offset by lower net realized commodity prices;

A $7 million favorable change in Other segment costs and expenses related to lower corporate costs.

Management’s Discussion and Analysis (Continued)

Management’s Discussion and Analysis of Financial Condition and Liquidity

Outlook

Our growth capital and investment expenditures in 2024 are expected to range from $1.45 billion to $1.75 billion, excluding acquisitions. Growth capital spending in 2024 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting growth in the Haynesville Basin, and projects supporting the Northeast G&P business. We also expect to invest capital in our Other business ventures. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that reduce emissions, and meet legal, regulatory, and/or contractual commitments. We intend to fund substantially all planned 2024 capital spending with cash available after paying dividends. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities including the repurchase of our common stock.

On January 3, 2024, we acquired 100 percent of a strategic portfolio of natural gas storage facilities and pipelines, located in Louisiana and Mississippi for $1.95 billion. The acquisition was funded with cash on hand and $100 million of deferred consideration that does not accrue interest and is payable one year from the acquisition date.

On August 1, 2024, we completed the Discovery Acquisition for $170 million. Also, on August 1, 2024, we completed the sale of certain equity-method investments for $160 million (see Note 11 – Subsequent Events).

On January 5, 2024, we issued $2.1 billion in long-term debt. We retired long-term debt of $1.0 billion on March 4, 2024, and $1.25 billion on June 24, 2024 (see Note 6 – Debt and Banking Arrangements).

As of June 30, 2024, we have approximately $1.536 billion of long-term debt due within one year. Our potential sources of liquidity available to address these maturities include cash on hand, proceeds from refinancing, our credit facility, or our commercial paper program, as well as proceeds from asset monetizations.

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2024. Our potential material internal and external sources and uses of liquidity are as follows:


Sources:
			Cash and cash equivalents on hand
			Cash generated from operations
			Distributions from our equity-method investees
			Utilization of our credit facility and/or commercial paper program
			Cash proceeds from issuance of debt and/or equity securities
			Proceeds from asset monetizations
Uses:
			Working capital requirements
			Capital and investment expenditures
			Product costs
			Gas & NGL Marketing Services payments for transportation and storage capacity and gas supply
			Other operating costs including human capital expenses
			Quarterly dividends to our shareholders
			Repayments of borrowings under our credit facility and/or commercial paper program
			Debt service payments, including payments of long-term debt
			Distributions to noncontrolling interests
			Share repurchase program

Management’s Discussion and Analysis (Continued)

As of June 30, 2024, we have approximately $24.1 billion of long-term debt due after one year. Our potential sources of liquidity available to address these maturities include cash generated from operations, proceeds from refinancing, our credit facility, or our commercial paper program, as well as proceeds from asset monetizations.

Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook*.*

As of June 30, 2024, we had a working capital deficit of $2.581 billion, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:


Available Liquidity	June 30, 2024
	(Millions)
Cash and cash equivalents	$	55
Capacity available under our $3.75 billion credit facility, less amounts outstanding under our $3.5 billion commercial paper program (1)	3,119
	$	3,174

(1)In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. We had $631 million of Commercial paper (at par value) outstanding as of June 30, 2024. Through June 30, 2024, the highest amount outstanding under our commercial paper program and credit facility during 2024 was $730 million. At June 30, 2024, we were in compliance with the financial covenants associated with our credit facility.

Dividends

We increased our regular quarterly cash dividend to common stockholders by approximately 6.1 percent from the $0.4475 per share paid in each quarter of 2023, to $0.4750 per share paid in March and June 2024.

Registrations

In February 2024, we filed a shelf registration statement as a well-known seasoned issuer.

Distributions from Equity-Method Investees

The organizational documents of entities in which we have an equity-method investment generally require periodic distributions of their available cash to their members. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses.

Credit Ratings

The interest rates at which we are able to borrow money are impacted by our credit ratings. The current ratings are as follows:


Rating Agency	Outlook	Senior Unsecured Debt Rating
S&P Global Ratings	Positive	BBB
Moody’s Investors Service	Stable	Baa2
Fitch Ratings	Stable	BBB

In April 2024, S&P Global Ratings changed its Outlook from Stable to Positive.

These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our securities, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current

Management’s Discussion and Analysis (Continued)

criteria for investment-grade ratios. A downgrade of our credit ratings might increase our future cost of borrowing and, if ratings were to fall below investment-grade, could require us to provide additional collateral to third parties, negatively impacting our available liquidity.

Sources (Uses) of Cash

The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented in the Consolidated Statement of Cash Flows (see Notes to Consolidated Financial Statements for the Notes referenced in the table):


	Cash Flow	Six Months Ended June 30,
	Category	2024		2023
		(Millions)
Sources of cash and cash equivalents:
Net cash provided (used) by operating activities	Operating	$	2,513	$	2,891
Proceeds from long-term debt	Financing	2,100		1,503






Uses of cash and cash equivalents:
Payments of long-term debt	Financing	(2,274)		(14)
Purchases of businesses, net of cash acquired (Note 3)	Investing	(1,844)		(1,053)
Common dividends paid	Financing	(1,158)		(1,091)
Capital expenditures	Investing	(1,123)		(1,155)

Dividends and distributions paid to noncontrolling interests	Financing	(130)		(112)
Proceeds from (payments of) commercial paper - net	Financing	(95)		(352)
Purchases of and contributions to equity-method investments	Investing	(82)		(69)
Purchases of treasury stock	Financing	—		(130)

Other sources / (uses) – net	Financing and Investing	(2)		(19)
Increase (decrease) in cash and cash equivalents		$	(2,095)	$	399

Operating activities

The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation and amortization, Provision (benefit) for deferred income taxes, Equity (earnings) losses, Net unrealized (gain) loss from commodity derivative instruments, Inventory write-downs, and Amortization of stock-based awards.

Our Net cash provided (used) by operating activities for the six months ended June 30, 2024 decreased from the same period in 2023 primarily due to unfavorable changes in margin requirements and net operating working capital partially offset by higher operating income (excluding non-cash items previously discussed).

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