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 Discovery, a former 60 percent equity-method investment in which we acquired the remaining ownership interest in August 2024 (see Note 3 – Acquisitions and Divestitures). 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 September 2024, we paid a regular quarterly dividend of $0.4750 per share.

Overview of Nine Months Ended September 30, 2024

Net income (loss) attributable to The Williams Companies, Inc. for the nine months ended September 30, 2024, decreased $302 million compared to the nine months ended September 30, 2023. Further discussion of our results is found in this report in the Results of Operations.

Recent Developments

Transco FERC Rate Case Filing

On August 30, 2024, Transco filed a general rate case with the FERC for an overall increase in rates. In September 2024, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2025, subject to refund and the outcome of hearing procedures established by the FERC. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2024, as requested by Transco, and will not be subject to refund. The impact of the rates reflecting a rate decrease is expected to reduce revenues by approximately $1 million per month beginning October 1, 2024.

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 November 2024 at the earliest. To enable us to continue operating the project facilities and capacity until the FERC issues an order on remand from the court’s decision, on September 6, 2024, we filed an application with the FERC for a temporary certificate.

Management’s Discussion and Analysis (Continued)

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 cash, subject to working capital and post-closing adjustments. As a result of acquiring this additional interest, we obtained control and now consolidate Discovery. We recognized a $127 million gain on remeasuring our existing equity-method investment to fair value included in Other investing income (loss) – net in our Consolidated Statement of Income in the third quarter of 2024. The purpose of this acquisition was to expand our gathering, processing, and transportation presence in the Gulf of Mexico region. Discovery continues to be reported within our Transmission & Gulf of Mexico segment (see Note 3 – Acquisitions and Divestitures).

Sale of Aux Sable Interest

Also on August 1, 2024, we completed the sale of our equity-method investments in Aux Sable in our Northeast G&P segment for total consideration of $161 million. As a result of this sale, we recorded a gain of $149 million included in Other investing income (loss) – net in our Consolidated Statement of Income in the third quarter of 2024 (see Note 3 – Acquisitions and Divestitures).

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,

Management’s Discussion and Analysis (Continued)

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;

• 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.

Management’s Discussion and Analysis (Continued)

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 placed a portion of the project into service in November 2024. We plan to place the remainder of the project into service by year-end 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 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

In October 2024, we filed a certificate application with 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 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 1,597 Mdth/d.

Gillis West

We plan to file our prior notice application for the project with the FERC in the first quarter of 2025, 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

Management’s Discussion and Analysis (Continued)

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 October 2024, we received approval from 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.

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 third quarter 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 nine months ended September 30, 2024, compared to the three and nine months ended September 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 September 30,												Change*												Nine Months Ended September 30,												Change*
			2024						2023						$						%						2024						2023						$						%
			(Dollars in millions)																								(Dollars in millions)
Revenues:
Service revenues			$	1,911					$	1,770					+141						+8		%				$	5,653					$	5,212					+441						+8		%
Product sales and service revenues – commodity consideration			737						765						-28						-4		%				2,240						2,266						-26						-1		%
Net gain (loss) from commodity derivatives			5						24						-19						-79		%				(133)						645						-778						NM
Total revenues			2,653						2,559																		7,760						8,123
Costs and expenses:
Product costs and net processing commodity expenses			524						515						-9						-2		%				1,496						1,587						+91						+6		%
Operating and maintenance expenses			580						522						-58						-11		%				1,613						1,466						-147						-10		%
Depreciation and amortization expenses			566						521						-45						-9		%				1,654						1,542						-112						-7		%
Selling, general, and administrative expenses			170						146						-24						-16		%				520						483						-37						-8		%
Gain on sale of business			—						(130)						-130						-100		%				—						(130)						-130						-100		%
Other (income) expense – net			(25)						(9)						+16						+178		%				(69)						(49)						+20						+41		%
Total costs and expenses			1,815						1,565																		5,214						4,899
Operating income (loss)			838						994																		2,546						3,224
Equity earnings (losses)			147						127						+20						+16		%				431						434						-3						-1		%
Other investing income (loss) – net			290						24						+266						NM						332						45						+287						NM
Interest expense			(338)						(314)						-24						-8		%				(1,026)						(914)						-112						-12		%
Other income (expense) – net			31						30						+1						+3		%				95						69						+26						+38		%
Income (loss) before income taxes			968						861																		2,378						2,858
Less: Provision (benefit) for income taxes			227						176						-51						-29		%				549						635						+86						+14		%
Income (loss) from continuing operations			741						685																		1,829						2,223
Income (loss) from discontinued operations			—						(1)						+1						+100		%				—						(88)						+88						+100		%
Net income (loss)			741						684																		1,829						2,135
Less: Net income attributable to noncontrolling interests			35						30						-5						-17		%				90						94						+4						+4		%
Net income (loss) attributable to The Williams Companies, Inc.			$	706					$	654					+52						+8		%				$	1,739					$	2,041					-302						-15		%

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• • = 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 September 30, 2024 vs. three months ended September 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 and the August 2024 Discovery Acquisitions 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 West and Northeast G&P 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 decrease primarily consists of:

*•*Lower product sales from our upstream operations at Other;

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

• Lower system management gas sales primarily at our Transmission & Gulf of Mexico segment; partially offset by

• Higher marketing sales activities primarily at our West segment; partially offset by lower marketing activities related to NGLs at our Gas & NGL Marketing Services segment.

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 increase primarily consists of:

• Higher marketing activities primarily at our West segment; partially offset by lower marketing activities primarily related to NGLs at our Gas & NGL Marketing Services segment; partially offset by

• Lower shrink natural gas purchases and commodity consideration costs associated with our equity NGL production activities primarily at our West segment;

• Lower system management gas purchases primarily at our Transmission & Gulf of Mexico segment.

Operating and maintenance expenses increased primarily due to employee-related costs, including the impact of a change in a payroll policy; and operating costs of the assets acquired at our West and Transmission & Gulf of Mexico segments.

Management’s Discussion and Analysis (Continued)

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

Selling, general, and administrative expenses increased primarily due to employee-related costs, including the impact of a change in a payroll policy.

Gain on sale of business reflects a gain from the sale of certain liquids pipelines in our Transmission & Gulf of Mexico segment in 2023 (see Note 3 – Acquisitions and Divestitures).

Other (income) expense – net within Operating income (loss) includes lower project feasibility costs at our Transmission & Gulf of Mexico segment.

Equity earnings (losses) changed favorably primarily due to the absence of our share of a loss contingency accrual in 2023 at Aux Sable, partially offset by the impacts of the sale of our interests in Aux Sable and the consolidations of RMM and Discovery following our acquisitions of the remaining ownership interests (see Note 3 – Acquisitions and Divestitures).

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

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 unfavorably primarily due to higher pre-tax income and the absence of a benefit associated with decreases in our estimate of the state deferred income tax rate in 2023. 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.

Nine months ended September 30, 2024 vs. nine months ended September 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, February 2023 MountainWest and August 2024 Discovery Acquisitions at our Transmission & Gulf of Mexico segment, and higher revenues associated with an expansion project at our Transmission & Gulf of Mexico segment, partially offset by lower gathering volumes at our West and Northeast G&P segments and the September 2023 sale of certain liquids pipelines at our Transmission & Gulf of Mexico segment.

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

• Lower system management gas sales primarily at our Transmission & Gulf of Mexico segment;

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

• Lower product sales from upstream operations at Other; partially offset by

• Higher marketing sales activities primarily at our West segment; partially offset by lower marketing sales activities primarily related to NGLs at our Gas & NGL Marketing Services segment. Net natural gas marketing sales were impacted by lower net prices, higher storage costs, and a favorable change in lower of cost or net realizable inventory adjustments.

Management’s Discussion and Analysis (Continued)

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.

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

• Lower shrink natural gas purchases and commodity consideration costs associated with our equity NGL production activities primarily at our West segment;

• Lower system management gas purchases primarily at our Transmission & Gulf of Mexico segment; partially offset by

• Higher marketing activities primarily at our West segment; partially offset by lower marketing activities primarily related to NGLs at our Gas & NGL Marketing Services segment.

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 unfavorable changes in employee-related costs, including the impact of a change in a payroll policy; and 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. The increase is partially offset by lower amortization of intangibles related to our 2021 Sequent Acquisition.

Selling, general, and administrative expenses increased primarily due to employee-related costs, including the impact of a change in a payroll policy.

Gain on sale of business reflects a gain from the sale of certain liquids pipelines in our Transmission & Gulf of Mexico segment in 2023, as previously discussed.

Other (income) expense – net within Operating income (loss) includes lower project feasibility costs at our Transmission & Gulf of Mexico segment.

Equity earnings (losses) changed unfavorably primarily due to the impacts of the consolidation of RMM and Discovery and the sale of our interests in Aux Sable, partially offset by the absence of our share of a loss contingency accrual in 2023 at Aux Sable, as previously discussed, and favorable results at OPPL.

Other investing income (loss) – net includes gains on the sale of our interests in Aux Sable and associated with the purchase of the remaining interest in Discovery, as previously discussed.

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.

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.

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

Income (loss) from discontinued operations in 2023 includes a pre-tax charge of $116 million to increase the accrued liability associated with our Alaska refinery contamination litigation, partially offset by the related income tax effect.

Management’s Discussion and Analysis (Continued)

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 September 30,												Nine Months Ended September 30,
			2024						2023						2024						2023
			(Millions)
Service revenues			$	1,072					$	978					$	3,144					$	2,874
Product sales and service revenues – commodity consideration (1)			98						74						213						226
Net realized gain (loss) from commodity derivatives (1)			—						1						—						2
Segment revenues			1,170						1,053						3,357						3,102
Product costs and net processing commodity expenses (1)			(87)						(68)						(188)						(203)
Other segment costs and expenses			(313)						(286)						(857)						(855)
Gain on sale of business			—						130						—						130
Proportional Modified EBITDA of equity-method investments			41						52						136						153
Transmission & Gulf of Mexico Modified EBITDA			$	811					$	881					$	2,448					$	2,327
Commodity margins			$	11					$	7					$	25					$	25

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(1)Included as a component of Commodity margins.

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

Transmission & Gulf of Mexico Modified EBITDA decreased primarily due to the absence of a Gain on sale of business and higher Other segment costs and expenses, partially offset by higher Service revenues.

Service revenues increased primarily due to:

*•*A $57 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 $36 million increase in Transco’s revenues associated with the Regional Energy Access expansion project placed partially in-service in the fourth quarter of 2023 and full in-service in August 2024;

*•*A $13 million increase primarily in gathering and transportation revenues at Discovery due to the acquisition in August 2024 (see Note 3 – Acquisitions and Divestitures); partially offset by

• A $14 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);

• A $6 million decrease in the Eastern Gulf region primarily due to weather-related events and ongoing producer operational issues at Gulfstar One in the Gunflint field, partially offset by higher primarily production handling volumes from a new well at Gulfstar One in the Pickerel field.

Management’s Discussion and Analysis (Continued)

Other segment costs and expenses increased primarily due to:

*•*Higher operating expenses and administrative costs including higher operating costs related to our Gulf Coast Storage and Discovery Acquisitions and higher employee-related costs, including the impact of a change in a payroll policy; partially offset by lower operating costs related to the sale of certain liquids pipelines in the Gulf Coast region; partially offset by

• Lower project feasibility costs.

Gain on sale of business reflects a gain recognized on the sale of certain liquids pipelines in the Gulf Coast region in September 2023 (see Note 3 – Acquisitions and Divestitures).

Proportional Modified EBITDA of equity-method investments decreased due to lower proportional results as Discovery was consolidated following our acquisition of the remaining ownership interest in August 2024.

Nine months ended September 30, 2024 vs. nine months ended September 30, 2023

Transmission & Gulf of Mexico Modified EBITDA increased primarily due to higher Service revenues, partially offset by the absence of a Gain on sale of business.

Service revenues increased primarily due to:

*•*A $165 million increase due to the acquisition of Gulf Coast Storage assets primarily in storage revenues;

• A $76 million increase in Transco’s revenues associated with the Regional Energy Access expansion project;

• A $37 million increase in primarily transportation and storage revenues at MountainWest primarily due to the acquisition in February 2023 (see Note 3 – Acquisitions and Divestitures);

• A $16 million increase in NorTex’s revenues primarily associated with higher storage rates;

*•*A $13 million increase primarily in gathering and transportation revenues at Discovery due to the acquisition; partially offset by

• A $39 million decrease due to the sale of certain liquids pipelines in the Gulf Coast region primarily in transportation revenues;

• A $19 million decrease in the Eastern Gulf region primarily due to shut-ins for weather-related events and producer operational issues at Gulfstar One in the Gunflint and Tubular Bells fields, partially offset by higher primarily production handling volumes from a new well at Gulfstar One in the Pickerel field.

Other segment costs and expenses increased primarily due to:

*•*Higher operating expenses and administrative costs including higher operating, acquisition and transition costs related to our Gulf Coast Storage, Discovery, and MountainWest Acquisitions; higher employee-related costs, including the impact of a change in a payroll policy; partially offset by significantly lower acquisition and transition costs related to our MountainWest Acquisition and lower operating costs related to the sale of certain liquids pipelines in the Gulf Coast region; partially offset by

• Lower project feasibility costs;

*•*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.

Management’s Discussion and Analysis (Continued)

Gain on sale of business reflects a gain recognized on the sale of certain liquids pipelines in the Gulf Coast region in 2023, as previously discussed.

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

Northeast G&P

			Three Months Ended September 30,												Nine Months Ended September 30,
			2024						2023						2024						2023
			(Millions)
Service revenues			$	475					$	478					$	1,419					$	1,421
Product sales and service revenues – commodity consideration (1)			27						27						75						107
Segment revenues			502						505						1,494						1,528
Product costs and net processing commodity expenses (1)			(19)						(20)						(56)						(96)
Other segment costs and expenses			(156)						(150)						(436)						(414)
Proportional Modified EBITDA of equity-method investments			149						119						459						421
Northeast G&P Modified EBITDA			$	476					$	454					$	1,461					$	1,439
Commodity margins			$	8					$	7					$	19					$	11

(1)Included as a component of Commodity margins.

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

Northeast G&P Modified EBITDA increased primarily due to higher Proportional Modified EBITDA of equity-method investments.

Service revenues decreased primarily due to:

*•*A $20 million decrease in gathering revenues at Susquehanna Supply Hub primarily related to lower volumes partially offset by escalated rates; partially offset by

• An $11 million increase in revenues at the Northeast JV primarily related to higher gathering and processing volumes and rates.

Other segment costs and expenses increased primarily due to higher employee-related costs, including the impact of a change in a payroll policy.

Proportional Modified EBITDA of equity-method investments increased at Aux Sable Liquid Products LP primarily due to the absence of our $31 million share of a loss contingency accrual related to our 14 percent ownership in the third quarter of 2023, partially offset by the sale of our investment in Aux Sable Liquid Products LP in the third quarter of 2024. Additionally, Appalachia Midstream Investments increased primarily driven by higher gathering rates partially offset by lower volumes and higher expenses.

Nine months ended September 30, 2024 vs. nine months ended September 30, 2023

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

Management’s Discussion and Analysis (Continued)

Service revenues decreased primarily due to:

*•*A $15 million decrease in gathering revenues in the Utica Shale region primarily related to lower volumes at Flint and Cardinal partially offset by escalated rates;

• A $9 million decrease in gathering revenues at Susquehanna Supply Hub primarily related to lower volumes partially offset by escalated rates; partially offset by

*•*A $12 million increase in joint venture operating fees primarily related to assuming operatorship of Blue Racer effective January 1, 2024 (which is significantly offset by higher Other segment costs and expenses discussed below).

Other segment costs and expenses increased primarily due to higher employee-related costs, including the impact of a change in a payroll policy, as well as increased support costs related to 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 absence of our $31 million share of a loss contingency accrual related to our 14 percent ownership in the third quarter of 2023, as well as the terms of the new product marketing agreement, partially offset by the sale of our investment in Aux Sable Liquid Products LP in the third quarter of 2024. Additionally, Appalachia Midstream Investments increased primarily driven by higher gathering rates partially offset by lower volumes at the Bradford Supply Hub and higher expenses.

West

			Three Months Ended September 30,												Nine Months Ended September 30,
			2024						2023						2024						2023
			(Millions)
Service revenues			$	426					$	374					$	1,270					$	1,088
Product sales and service revenues – commodity consideration (1)			237						146						710						363
Net realized gain (loss) from commodity derivatives relating to service revenues			—						12						10						80
Net realized gain (loss) from commodity derivatives relating to product sales (1)			—						1						(5)						5
Net realized gain (loss) from commodity derivatives			—						13						5						85
Segment revenues			663						533						1,985						1,536
Product costs and net processing commodity expenses (1)			(210)						(126)						(636)						(353)
Other segment costs and expenses			(165)						(137)						(477)						(373)
Proportional Modified EBITDA of equity-method investments			35						45						96						121
West Modified EBITDA			$	323					$	315					$	968					$	931
Commodity margins			$	27					$	21					$	69					$	15

---

(1) Included as a component of Commodity margins.

Management’s Discussion and Analysis (Continued)

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

West Modified EBITDA increased primarily due to 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 $76 million increase in the DJ Basin region associated with the DJ Basin Acquisitions in November 2023 (see Note 3 – Acquisitions and Divestitures);

• A $7 million increase in our other NGL operations primarily associated with higher transportation revenue due to higher volumes; partially offset by

• A $16 million decrease in the Haynesville Shale region primarily associated with lower gathering volumes from decreased producer activity;

• An $8 million decrease in the Barnett Shale region primarily due to lower gathering volumes as well as lower gathering rates driven by unfavorable commodity pricing;

• A $7 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenues.

Net realized gain (loss) from commodity derivatives relating to service revenues is unfavorable due to the absence of realized hedge positions in third-quarter 2024.

Commodity margins increased $6 million primarily driven by higher marketing margins associated with the DJ Basin Acquisitions.

Other segment costs and expenses increased primarily due to higher operating expenses including those resulting from the DJ Basin Acquisitions and the impact of a change in a payroll policy.

Proportional Modified EBITDA of equity-method investments decreased primarily due to lower proportional results as RMM was consolidated following our acquisition of the remaining ownership interest on November 30, 2023, partially offset by higher volumes at OPPL.

Nine months ended September 30, 2024 vs. nine months ended September 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 $216 million increase in the DJ Basin region associated with the DJ Basin Acquisitions in November 2023, as previously discussed;

• A $27 million increase in our other NGL operations associated with higher transportation and fractionation 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

• A $32 million decrease in the Haynesville Shale region primarily due to lower gathering volumes from decreased producer activity, partially offset by higher gathering rates;

Management’s Discussion and Analysis (Continued)

• A $25 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenues as well as lower gathering volumes;

• A $22 million decrease in the Barnett Shale region primarily due to lower gathering rates driven by unfavorable commodity pricing and lower gathering volumes.

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

Commodity margins increased $54 million primarily due to $30 million higher margins associated with the DJ Basin Acquisitions. Margins also increased $19 million from our equity NGLs due to lower net realized prices for natural gas purchases and lower volumes of natural gas purchased both associated with our equity NGL production activities; partially offset by lower volumes of equity NGL sold and lower net realized NGL sales prices.

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

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

Gas & NGL Marketing Services

			Three Months Ended September 30,												Nine Months Ended September 30,
			2024						2023						2024						2023
			(Millions)
Service revenues			$	—					$	—					$	—					$	1
Product sales (1)			481						556						1,491						1,658
Net realized gain (loss) from commodity derivative instruments (1)			(8)						(31)						40						41
Net unrealized gain (loss) from commodity derivative instruments			9						33						(188)						494
Net gain (loss) from commodity derivatives			1						2						(148)						535
Segment revenues			482						558						1,343						2,194
Net unrealized gain (loss) from commodity derivative instruments within Net processing commodity expenses			1						(9)						(3)						(43)
Product costs (1)			(450)						(487)						(1,269)						(1,398)
Other segment costs and expenses			(22)						(19)						(85)						(75)
Gas & NGL Marketing Services Modified EBITDA			$	11					$	43					$	(14)					$	678
Commodity margins			$	23					$	38					$	262					$	301

---

(1) Included as a component of Commodity margins.

Three months ended September 30, 2024 vs. three months ended September 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.

Management’s Discussion and Analysis (Continued)

Commodity margins decreased $15 million primarily due to a $17 million decrease in our NGL marketing margins including an unfavorable change in net realized gains and losses on sale of inventory in 2024 compared to 2023 driven by unfavorable changes in non-ethane prices.

Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and Net processing commodity expenses relates to derivative contracts that are not designated as hedges for accounting purposes. The change from 2023 is primarily due to a change in forward commodity prices relative to our hedge positions in 2024 compared to 2023.

Nine months ended September 30, 2024 vs. nine months ended September 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 $39 million primarily due to:

• A $27 million decrease in our natural gas marketing margins including $19 million of lower natural gas storage marketing margins primarily driven by less favorable realized derivative gains and higher storage fees, partially offset by a favorable change of $13 million in lower cost or net realizable value inventory adjustment. The decrease in our natural gas marketing margins also includes $8 million of lower natural gas transportation capacity marketing margins due to less favorable net realized pricing spreads;

*•*A $12 million decrease in our NGL marketing margins including an unfavorable change in net realized gains and losses on sale of inventory in 2024 compared to 2023 driven by unfavorable changes in non-ethane prices.

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 September 30,												Nine Months Ended September 30,
			2024						2023						2024						2023
			(Millions)
Service revenues			$	4					$	4					$	12					$	12
Product sales (1)			95						118						289						303
Net realized gain (loss) from derivative instruments (1)			1						9						29						41
Net unrealized gain (loss) from derivative instruments			3						(1)						(19)						(18)
Net gain (loss) from commodity derivatives			4						8						10						23
Segment revenues			103						130						311						338
Other segment costs and expenses			(47)						(48)						(132)						(140)
Proportional Modified EBITDA of equity-method investments			2						(1)						2						(2)
Modified EBITDA of other business activities			$	58					$	81					$	181					$	196
Net realized product sales			$	96					$	127					$	318					$	344

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

Management’s Discussion and Analysis (Continued)

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

Modified EBITDA of other business activities decreased primarily due to:

• A $31 million decrease in Net realized product sales from our upstream operations primarily due to lower net realized commodity prices and lower production volumes.

Nine months ended September 30, 2024 vs. nine months ended September 30, 2023

Modified EBITDA of other business activities decreased primarily due to:

*•*A $26 million decrease in Net realized product sales from our upstream operations primarily due to lower net realized commodity prices and lower volumes associated with our South Mansfield production in the Haynesville Shale region, partially offset by higher production volumes associated with our Wamsutter region production.

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 November 1, 2024, we paid the remaining $651 million of the RMM purchase price obligation (see Note 3 – Acquisitions and Divestitures).

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 $161 million (see Note 3 – Acquisitions and Divestitures).

On January 3, 2024, we completed the Gulf Coast Storage Acquisition for $1.95 billion (see Note 3 – Acquisitions and Divestitures).

Our long-term debt activity during the first nine months of 2024 included issuing $3.6 billion of new debt and retiring $2.25 billion of existing debt (see Note 6 – Debt and Banking Arrangements).

As of September 30, 2024, we have approximately $2.284 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 September 30, 2024, we have approximately $24.8 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 September 30, 2024, we had a working capital deficit of $2.021 billion, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:

Available Liquidity						September 30, 2024
						(Millions)
Cash and cash equivalents						$	762
Capacity available under our $3.75 billion credit facility, less amounts outstanding under our $3.5 billion commercial paper program (1)						3,750
						$	4,512

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(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 no Commercial paper outstanding as of September 30, 2024. Through September 30, 2024, the highest amount outstanding under our commercial paper program and credit facility during 2024 was $730 million. We expect to be in compliance with the financial covenants associated with our credit facility for the September 30, 2024, reporting period.

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 the first three quarters of 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.

Management’s Discussion and Analysis (Continued)

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 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						Nine Months Ended September 30,
			Category						2024						2023
									(Millions)
Sources of cash and cash equivalents:
Net cash provided (used) by operating activities			Operating						$	3,756					$	4,125
Proceeds from long-term debt			Financing						3,594						2,754
Proceeds from sale of business (Note 3)			Investing						—						348
Proceeds from dispositions of equity-method investments (Note 3)			Investing						161						—
Uses of cash and cash equivalents:
Payments of long-term debt			Financing						(2,286)						(21)
Purchases of businesses, net of cash acquired (Note 3)			Investing						(1,995)						(1,024)
Common dividends paid			Financing						(1,737)						(1,635)
Capital expenditures			Investing						(1,805)						(1,845)
Dividends and distributions paid to noncontrolling interests			Financing						(178)						(174)
Proceeds from (payments of) commercial paper – net			Financing						(723)						(352)
Purchases of and contributions to equity-method investments			Investing						(101)						(80)
Purchases of treasury stock			Financing						—						(130)
Other sources / (uses) – net			Financing and Investing						(74)						(44)
Increase (decrease) in cash and cash equivalents									$	(1,388)					$	1,922

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, Gain on sale of business, Gain on disposition of equity-method investments, Gain on consolidation of equity-method investments, Inventory write-downs, and Amortization of stock-based awards.

Our Net cash provided (used) by operating activities for the nine months ended September 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).