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

Overview of Three Months Ended March 31, 2024

Net income (loss) attributable to The Williams Companies, Inc. for the three months ended March 31, 2024, decreased $295 million compared to the three months ended March 31, 2023. Further discussion of our results is found in this report in the Results of Operations.

Recent Developments

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, is 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, and a decrease in expected volumes primarily in the Appalachian Basin 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

Management’s Discussion and Analysis (Continued)

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 fourth quarter of 2024.

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)

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 plan to place the remainder of 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 829 Mdth/d.

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 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 this 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

Management’s Discussion and Analysis (Continued)

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.

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.

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 June 2022, we announced our intention to construct 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 half 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 months ended March 31, 2024, compared to the three months ended March 31, 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 March 31,
			2024						$ Change from 2023*						% Change from 2023*						2023
			(Dollars in millions)
Revenues:
Service revenues			$	1,905					+211						+12		%				$	1,694
Product sales and service revenues – commodity consideration			875						-6						-1		%				881
Net gain (loss) from commodity derivatives			(9)						-515						NM						506
Total revenues			2,771																		3,081
Costs and expenses:
Product costs and net processing commodity expenses			531						+76						+13		%				607
Operating and maintenance expenses			511						-48						-10		%				463
Depreciation and amortization expenses			548						-42						-8		%				506
Selling, general, and administrative expenses			186						-10						-6		%				176
Other (income) expense – net			(17)						-14						-45		%				(31)
Total costs and expenses			1,759																		1,721
Operating income (loss)			1,012																		1,360
Equity earnings (losses)			137						-10						-7		%				147
Other investing income (loss) – net			24						+16						+200		%				8
Interest expense			(349)						-55						-19		%				(294)
Other income (expense) – net			31						+11						+55		%				20
Income (loss) before income taxes			855																		1,241
Less: Provision (benefit) for income taxes			193						+91						+32		%				284
Net income (loss)			662																		957
Less: Net income (loss) attributable to noncontrolling interests			30						—						—		%				30
Net income (loss) attributable to The Williams Companies, Inc.			$	632					-295						-32		%				$	927

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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.

Three months ended March 31, 2024 vs. three months ended March 31, 2023

Service revenues increased primarily due to higher volumes from acquisitions at our Transmission & Gulf of Mexico and West segments, and higher revenues associated with expansion projects at our Transmission & Gulf of Mexico segment.

The net sum of Product sales and service revenues – commodity consideration, Product costs and net processing commodity expenses, and net realized gains and losses on commodity derivatives related to sales of product and shrink gas purchases for 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 below. The sum of Product sales and net realized gains and losses on commodity derivatives related to our upstream operations comprise Net realized product sales.

Management’s Discussion and Analysis (Continued)

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

• Lower equity NGL sales and commodity consideration revenues primarily due to lower prices substantially offset by higher non-ethane volumes;

• Lower NGL marketing sales primarily due to lower prices and lower volumes; partially offset by

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

• Higher product sales from our upstream operations primarily due to higher production volumes substantially offset by lower commodity prices.

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 is not recognized until the underlying transaction occurs.

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

• Lower marketing prices and volumes for our NGL marketing activities; and

• Lower shrink gas purchases associated with our equity NGL production activities due to lower natural gas prices.

Operating and maintenance expenses increased primarily related to operating costs of the assets acquired in the November 2023 DJ Basin Acquisitions, the January 2024 Gulf Coast Storage Acquisition, and the February 2023 MountainWest Acquisition.

Depreciation and amortization expenses increased primarily related to assets acquired in the Gulf Coast Storage Acquisition, the DJ Basin Acquisitions, and the MountainWest Acquisition.

Equity earnings (losses) changed unfavorably primarily due to the consolidation of RMM following our acquisition of the remaining ownership interest in November 2023.

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 Gulf Coast Storage and DJ Basin 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.

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’s Discussion and Analysis (Continued)

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 March 31,
															2024						2023
															(Millions)
Service revenues															$	1,049					$	940
Product sales and service revenues – commodity consideration (1)															70						67
Segment revenues															1,119						1,007
Product costs and net processing commodity expenses (1)															(61)						(57)
Other segment costs and expenses															(275)						(288)
Proportional Modified EBITDA of equity-method investments															46						53
Transmission & Gulf of Mexico Modified EBITDA															$	829					$	715
Commodity margins															$	9					$	10

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(1)Included as a component of Commodity margins.

Three months ended March 31, 2024 vs. three months ended March 31, 2023

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

Service revenues increased primarily due to:

*•*A $50 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 $35 million increase due to the acquisition of MountainWest in February 2023 primarily in transportation and 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 $13 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 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 related to our Gulf Coast Storage and MountainWest Acquisitions; substantially offset by lower costs related to timing and scope of general maintenance activities primarily at Transco and the sale of certain liquids pipelines in the Gulf Coast region.

Management’s Discussion and Analysis (Continued)

Northeast G&P

									Three Months Ended March 31,
															2024						2023
															(Millions)
Service revenues															$	479					$	454
Product sales and service revenues – commodity consideration (1)															30						55
Segment revenues															509						509
Product costs and net processing commodity expenses (1)															(19)						(50)
Other segment costs and expenses															(143)						(132)
Proportional Modified EBITDA of equity-method investments															157						143
Northeast G&P Modified EBITDA															$	504					$	470
Commodity margins															$	11					$	5

(1)Included as a component of Commodity margins.

Three months ended March 31, 2024 vs. three months ended March 31, 2023

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

Service revenues increased primarily due to:

*•*A $19 million increase in gathering revenues at Susquehanna Supply Hub primarily related to higher volumes associated with the Susquehanna Supply Hub gathering expansion project placed in-service in the fourth quarter of 2023 as well as escalated rates;

• A $9 million increase in revenues in the Utica Shale region primarily related to higher gathering rates resulting from the prior year annual cost of service contract redetermination at Cardinal, partially offset by lower volumes at Flint; partially offset by

*•*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.

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, and at Blue Racer primarily driven by higher gathering and processing volumes. Additionally, Appalachia Midstream Investments increased primarily driven by higher gathering rates offset by lower volumes at the Bradford Supply Hub. The increase was partially offset by a decrease at Laurel Mountain due to lower commodity-based gathering rates and lower volumes.

Management’s Discussion and Analysis (Continued)

West

									Three Months Ended March 31,
															2024						2023
															(Millions)
Service revenues															$	437					$	356
Product sales and service revenues – commodity consideration (1)															264						108
Net realized gain (loss) from commodity derivatives relating to service revenues															3						39
Net realized gain (loss) from commodity derivatives relating to product sales (1)															(3)						—
Net realized gain (loss) from commodity derivatives															—						39
Segment revenues															701						503
Product costs and net processing commodity expenses (1)															(249)						(132)
Other segment costs and expenses															(150)						(100)
Proportional Modified EBITDA of equity-method investments															25						33
West Modified EBITDA															$	327					$	304
Commodity margins															$	12					$	(24)

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(1) Included as a component of Commodity margins.

Three months ended March 31, 2024 vs. three months ended March 31, 2023

West Modified EBITDA increased primarily due 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 $71 million increase in the DJ Basin region primarily associated with the DJ Basin Acquisitions in November 2023 (see Note 3 – Acquisitions and Divestitures);

• A $13 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;

• A $12 million increase in our other NGL operations associated with higher fractionation revenue due to higher volumes and higher storage fees primarily due to a new contract; partially offset by

• A $10 million decrease in the Barnett Shale region primarily due to lower gathering rates driven by unfavorable commodity pricing;

• A $9 million decrease in the Eagle Ford Shale region primarily due to lower gathering volumes as well as lower MVC revenues.

Management’s Discussion and Analysis (Continued)

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 $36 million primarily due to a $30 million increase from our equity NGLs due to a favorable change in net realized commodity pricing primarily for shrink gas purchases and a $5 million increase from other sales activities associated primarily with the Cureton Acquisition.

Other segment costs and expenses increased primarily due to higher operating expenses related to 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.

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.

Gas & NGL Marketing Services

									Three Months Ended March 31,
															2024						2023
															(Millions)
Service revenues															$	—					$	1
Product sales (1)															587						675
Net realized gain (loss) from commodity derivative instruments (1)															81						117
Net unrealized gain (loss) from commodity derivative instruments															(98)						338
Net gain (loss) from commodity derivatives															(17)						455
Segment revenues															570						1,131
Net unrealized gain (loss) from commodity derivative instruments within Net processing commodity expenses															3						(5)
Product costs (1)															(432)						(527)
Other segment costs and expenses															(40)						(32)
Gas & NGL Marketing Services Modified EBITDA															$	101					$	567
Commodity margins															$	236					$	265

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(1) Included as a component of Commodity margins.

Three months ended March 31, 2024 vs. three months ended March 31, 2023

Gas & NGL Marketing Services Modified EBITDA decreased primarily due to an unfavorable change in Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and lower Commodity margins.

Commodity margins decreased $29 million primarily due to a $26 million decrease in our natural gas marketing margins including $15 million of lower natural gas transportation capacity marketing margins due to less favorable net realized pricing spreads. The decrease in our natural gas marketing margins also includes $11 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 in lower cost or net realizable value inventory adjustment.

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.

Other

									Three Months Ended March 31,
															2024						2023
															(Millions)
Service revenues															$	4					$	3
Product sales (1)															108						102
Net realized gain (loss) from commodity derivative instruments (1)															5						18
Net unrealized gain (loss) from commodity derivative instruments															3						(6)
Net gain (loss) from commodity derivatives															8						12
Segment revenues															120						117
Other segment costs and expenses															(44)						(43)
Modified EBITDA of other business activities															$	76					$	74
Net realized product sales															$	113					$	120

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

Three months ended March 31, 2024 vs. three months ended March 31, 2023

Modified EBITDA of other business activities increased slightly primarily due to:

*•*A $9 million favorable change in Net unrealized gain (loss) from commodity derivative instruments due to changes in forward commodity prices relative to our upstream hedge positions in 2024 compared to 2023; partially offset by

• A $7 million decrease in Net realized product sales from our upstream operations primarily due to lower net realized commodity prices, partially offset by higher production volumes.

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

As of March 31, 2024, we have approximately $2.787 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

As of March 31, 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*.*

Management’s Discussion and Analysis (Continued)

As of March 31, 2024, we had a working capital deficit of $2.371 billion, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:

Available Liquidity						March 31, 2024
						(Millions)
Cash and cash equivalents						$	667
Capacity available under our $3.75 billion credit facility, less amounts outstanding under our $3.5 billion commercial paper program (1)						3,750
						$	4,417

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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 March 31, 2024. Through March 31, 2024, the highest amount outstanding under our commercial paper program and credit facility during 2024 was $725 million. At March 31, 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 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 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.

Management’s Discussion and Analysis (Continued)

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						Three Months Ended March 31,
			Category						2024						2023
									(Millions)
Sources of cash and cash equivalents:
Proceeds from long-term debt			Financing						$	2,099					$	1,502
Net cash provided (used) by operating activities			Operating						1,234						1,514
Uses of cash and cash equivalents:
Purchases of businesses, net of cash acquired (Note 3)			Investing						(1,851)						(1,056)
Payments of long-term debt			Financing						(1,012)						(7)
Proceeds from (payments of) commercial paper - net			Financing						(723)						(352)
Common dividends paid			Financing						(579)						(546)
Capital expenditures			Investing						(544)						(545)
Dividends and distributions paid to noncontrolling interests			Financing						(64)						(54)
Purchases of and contributions to equity-method investments			Investing						(52)						(39)
Purchases of treasury stock			Financing						—						(74)
Other sources / (uses) – net			Financing and Investing						9						(18)
Increase (decrease) in cash and cash equivalents									$	(1,483)					$	325

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 three months ended March 31, 2024 decreased from the same period in 2023 primarily due to unfavorable changes in net operating working capital and margin requirements.