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.

• 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, and the Mid-Continent region which includes the Anadarko and Permian basins. This segment also includes our NGL storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, a 20 percent equity-method investment in Targa Train 7, and a 15 percent equity-method investment in Brazos Permian II.

• 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.

Management’s Discussion and Analysis (Continued)			Table of Contents

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, 2022 dated February 27, 2023.

Dividends

In September 2023, we paid a regular quarterly dividend of $0.4475 per share.

Overview of Nine Months Ended September 30, 2023

Net income (loss) attributable to The Williams Companies, Inc., for the nine months ended September 30, 2023, increased $661 million compared to the nine months ended September 30, 2022. Further discussion of our results is found in this report in the Results of Operations.

Recent Developments

Favorable Judgment Against Energy Transfer

On September 21, 2022, the Delaware Court of Chancery entered a final order and judgment awarding us the termination fee, attorney’s fees, expenses, and interest in the amount of $602 million plus additional interest starting September 17, 2022. Attorney fees of approximately $90 million will be payable upon receipt of the judgment amount. Energy Transfer appealed to the Delaware Supreme Court. On October 10, 2023, the Delaware Supreme Court issued an opinion affirming the Court of Chancery’s ruling. On October 25, 2023, Energy Transfer filed a motion for reargument with the Delaware Supreme Court. (See Note 9 – Contingencies of our Notes to Consolidated Financial Statements.)

DJ Basin Acquisitions

In October 2023, we agreed to acquire Cureton Front Range, LLC, whose operations are located in the Denver-Julesberg Basin (DJ Basin), for $560 million, subject to working capital and post-closing adjustments. Concurrently, we entered into an agreement to purchase an additional 50 percent interest in our equity-method investment RMM for $714 million. Upon closing, we will own 100 percent of and will consolidate RMM. These acquisitions are expected to close in the fourth quarter of 2023 and will expand our gathering and processing footprint in the DJ Basin. The Cureton Front Range, LLC acquisition is expected to be funded with available sources of short-term liquidity. Substantially all of the RMM purchase price is not due to the seller and does not accrue interest until the fourth quarter of 2024. These businesses will be reported within the West segment.

Sale of Certain Gulf Coast Liquids Pipelines

On September 29, 2023, we completed the sale of various petrochemical and feedstock pipelines and associated contracts in the Gulf Coast region for $348 million. As a result of this sale, we recorded a gain of $130 million in the third quarter of 2023 in our Transmission & Gulf of Mexico segment.

MountainWest Acquisition

On February 14, 2023, we closed on the acquisition of 100 percent of MountainWest, which includes FERC-regulated interstate natural gas pipeline systems and natural gas storage capacity, for $1.08 billion of cash, funded with available sources of short-term liquidity, and retaining $430 million outstanding principal amount of MountainWest long-term debt (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements). The MountainWest Acquisition expands our existing transmission and storage infrastructure footprint into major markets in Utah, Wyoming, and Colorado.

Management’s Discussion and Analysis (Continued)			Table of Contents

Northwest Pipeline FERC Rate Case Settlement

On November 15, 2022, Northwest Pipeline received approval from the FERC for a stipulation and settlement agreement which generally reduces rates effective January 1, 2023, resolves other rate issues, establishes a Modernization and Emission Reduction Program, and satisfies its rate case filing obligation. Provisions were included in the settlement that establish a moratorium on any proceedings that would seek to place new rates in effect any earlier than January 1, 2026, and that a general rate case filing will be made for rates to become effective not later than April 1, 2028, unless we have entered into a pre-filing settlement prior to that date.

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 2023 includes a continued focus on earnings and cash flow growth.

In 2023, our operating results are expected to benefit from the MountainWest Acquisition, volume growth in the Haynesville and Northeast G&P areas, annual inflation-based rate increases across our gathering and processing business, and partial in-service of the Regional Energy Access project. We also anticipate increases resulting from a full year of contribution from recently acquired Trace and NorTex assets. These increases are partially offset by 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 2023 are expected to be in a range from $1.6 billion to $1.9 billion, excluding acquisitions. Growth capital spending in 2023 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business and projects supporting growth in the Haynesville basin, including the Louisiana Energy Gateway project. We also expect to invest capital in the development of our upstream oil and gas properties. 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;

Management’s Discussion and Analysis (Continued)			Table of Contents

• 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, 2022, as filed with the SEC on February 27, 2023, as may be supplemented by disclosures 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.

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 a portion of the project into service in October 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 August 2022, we filed an application with the FERC for the project, which involves an expansion of Transco’s existing natural gas transmission system to provide firm transportation capacity from receipt points in south Texas to delivery points in Texas and Louisiana. We plan to place the project into service as early as the first quarter of 2025, assuming timely receipt of all necessary regulatory approvals. The project is expected to

Management’s Discussion and Analysis (Continued)			Table of Contents

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 August 2022, we filed an 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 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 August 2022, we filed an 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 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 April 2023, we filed an 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 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 approximately 64 Mdth/d.

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 fourth quarter of 2024.

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.

Northeast G&P

Susquehanna Supply Hub Gathering Expansion

We have an agreement in place with a third party to facilitate natural gas production growth in the Susquehanna region. We plan to construct approximately 22 miles of gathering pipeline and associated incremental compression. The system, once constructed, will add incremental capacity of 320 MMcf/d and will provide natural gas gathering services to the third party. The project is expected to go into service in the fourth quarter of 2023.

Management’s Discussion and Analysis (Continued)			Table of Contents

Utica Shale Gathering Expansion

We have an agreement in place with a third party to facilitate natural gas production growth in the Utica region on our Cardinal gathering system. We are constructing approximately 30 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. Phase 1 of this project was placed into service in the third quarter of 2023. Phase 2 of this project is expected to go into service in the fourth quarter of 2023.

Management’s Discussion and Analysis (Continued)			Table of Contents

Results of Operations

The following table and discussion is a summary of our consolidated results of operations for the three and nine months ended September 30, 2023, compared to the three and nine months ended September 30, 2022. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

			Three Months Ended September 30,																								Nine Months Ended September 30,
			2023						2022						$ Change*						% Change*						2023						2022						$ Change*						% Change*
			(Millions)																								(Millions)
Revenues:
Service revenues			$	1,770					$	1,685					+85						+5		%				$	5,212					$	4,828					+384						+8		%
Service revenues – commodity consideration			45						60						-15						-25		%				108						223						-115						-52		%
Product sales			720						1,260						-540						-43		%				2,158						3,475						-1,317						-38		%
Net gain (loss) on commodity derivatives			24						16						+8						+50		%				645						(491)						+1,136						NM
Total revenues			2,559						3,021																		8,123						8,035
Costs and expenses:
Product costs			484						990						+506						+51		%				1,458						2,650						+1,192						+45		%
Net processing commodity expenses			31						29						-2						-7		%				129						99						-30						-30		%
Operating and maintenance expenses			522						486						-36						-7		%				1,466						1,345						-121						-9		%
Depreciation and amortization expenses			521						500						-21						-4		%				1,542						1,504						-38						-3		%
Selling, general, and administrative expenses			146						163						+17						+10		%				483						477						-6						-1		%
Gain on sale of business			(130)						—						+130						NM						(130)						—						+130						NM
Other (income) expense – net			(9)						33						+42						NM						(49)						14						+63						NM
Total costs and expenses			1,565						2,201																		4,899						6,089
Operating income (loss)			994						820																		3,224						1,946
Equity earnings (losses)			127						193						-66						-34		%				434						492						-58						-12		%
Other investing income (loss) – net			24						1						+23						NM						45						4						+41						NM
Interest expense			(314)						(291)						-23						-8		%				(914)						(858)						-56						-7		%
Other income (expense) – net			30						(6)						+36						NM						69						5						+64						NM
Income (loss) before income taxes			861						717																		2,858						1,589
Less: Provision (benefit) for income taxes			176						96						-80						-83		%				635						169						-466						NM
Income (loss) from continuing operations			685						621																		2,223						1,420
Income (loss) from discontinued operations			(1)						—						-1						NM						(88)						—						-88						NM
Net income (loss)			684						621																		2,135						1,420
Less: Net income (loss) attributable to noncontrolling interests			30						21						-9						-43		%				94						40						-54						-135		%
Net income (loss) attributable to The Williams Companies, Inc.			$	654					$	600					+54						+9		%				$	2,041					$	1,380					+661						+48		%

• • = 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)			Table of Contents

Three months ended September 30, 2023 vs. three months ended September 30, 2022

Service revenues increased primarily due to higher volumes from the MountainWest Acquisition and higher gathering and processing volumes, as well as higher rates due to rate escalations and annual cost of service rate redetermination for certain of our Northeast G&P operations, partially offset by lower rates driven by unfavorable commodity pricing at our West operations.

Service revenues – commodity consideration decreased primarily due to lower NGL prices, partially offset by higher volumes. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold during the month processed and therefore are offset within Product costs below.

Product sales associated with our marketing sales activities decreased primarily due to lower commodity prices, partially offset by higher natural gas volumes. This decrease was substantially offset by lower natural gas marketing costs driven by lower prices as well as the benefit related to less significant lower of cost or net realizable value adjustments to our natural gas inventory in 2023 compared to 2022, partially offset by higher volumes. As we are acting as agent for natural gas marketing customers of our Gas & NGL Marketing Services segment, our natural gas marketing product sales are presented net of the related costs of those activities. Product sales from our upstream operations decreased primarily due to lower commodity prices, partially offset by higher commodity production volumes. Product sales also decreased due to lower system management gas sales, and lower equity NGL sales due to lower prices partially offset by higher volumes.

Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues primarily in our Gas & NGL Marketing Services, West, and Other segments (see Note 8 – Commodity Derivatives of Notes to Consolidated Financial Statements). 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 portfolio, upstream-related production, and natural gas and NGLs associated with exposure to commodity-based gathering and processing contracts. 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 contracts, which is not recognized until the underlying transaction occurs.

Product costs decreased primarily due to lower prices and volumes associated with our NGL marketing activities and lower system management gas purchases, as well as lower costs associated with NGLs acquired as commodity consideration related to our equity NGL production activities.

Net processing commodity expenses increased primarily due to the unfavorable changes related to gains and losses on commodity derivatives for processing plant shrink gas purchases (see Note 8 – Commodity Derivatives of Notes to Consolidated Financial Statements). This increase was partially offset by lower natural gas purchases associated with our equity NGL production activities primarily due to lower prices.

The sum of Service revenues – commodity consideration, Product sales, Product costs, net realized gains and losses on commodity derivatives related to sales of product, and net realized processing commodity expenses comprise our Commodity margins. However, Product sales and net realized gains and losses on commodity derivatives at our Other segment reflecting sales related to our oil and gas producing properties comprise Net realized product sales and are excluded from our Commodity margins. See Results of Operations— Period-Over-Period Operating Results - Segments for additional discussion of Commodity margins and Net realized product sales on a segment basis.

Operating and maintenance expenses increased primarily due to higher operating costs, including increased costs associated with the 2023 MountainWest Acquisition and the timing and scope of maintenance activities.

Depreciation and amortization expenses increased primarily related to our upstream assets, assets acquired in the 2023 MountainWest Acquisition, and higher depreciation at Transco. The increase is partially offset by lower amortization of intangibles related to our 2021 Sequent Acquisition.

Management’s Discussion and Analysis (Continued)			Table of Contents

Selling, general, and administrative expenses decreased primarily due to lower employee-related costs.

Gain on sale of business reflects a gain from the sale of various Gulf Coast petrochemical and feedstock pipelines in our Transmission & Gulf of Mexico segment in 2023 (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).

Other (income) expense – net within Operating income (loss) changed favorably primarily due to the absences of 2022 losses related to Eminence storage cavern abandonments and regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate.

The change in Equity earnings (losses) resulted from our share of a loss contingency accrual related to our 14 percent ownership in Aux Sable Liquid Products LP and a decrease at Laurel Mountain.

Other investing income (loss) – net changed favorably due to higher interest income earned on higher cash and cash equivalent balances.

Interest expense changed unfavorably primarily due to our 2023 debt issuances and MountainWest’s long-term debt (see Note 6 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements), partially offset by an increase in Interest capitalized related to ongoing expansion projects.

The favorable change in Other income (expense) – net below Operating income (loss) includes an increase in allowance for equity funds used during construction (equity AFUDC).

Provision (benefit) for income taxes changed unfavorably primarily due to a lower benefit associated with decreases in our estimate of the state deferred income tax rate in both periods and higher pre-tax income, partially offset by the absence of an unfavorable revision to a state net operating loss carryforward in 2022. See Note 5 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

Nine months ended September 30, 2023 vs. nine months ended September 30, 2022

Service revenues increased primarily due to higher volumes from the MountainWest and Trace Acquisitions, and the NorTex Asset Purchase, and higher gathering, processing, and transportation & fractionation volumes, and higher rates due to rate escalations and annual cost of service rate redetermination for certain Northeast G&P operations, as well as higher volumes at Transmission & Gulf of Mexico’s Eastern Gulf Coast region. An increase in the Haynesville Shale region, primarily associated with higher gathering volumes, was partially offset by lower rates driven by unfavorable commodity pricing at our West operations.

Service revenues – commodity consideration decreased primarily due to lower NGL prices and volumes. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold during the month processed and therefore are offset within Product costs below.

Product sales associated with our marketing sales activities decreased primarily due to lower natural gas and NGL prices and volumes. This decrease was substantially offset by lower natural gas marketing costs driven by lower prices and lower volumes, as well as a benefit related to less significant lower of cost or net realizable value adjustments to our natural gas inventory in 2023 compared to 2022. Product sales from our upstream operations decreased due to lower commodity prices, offset by higher commodity production volumes. Product sales also decreased due to lower prices and volumes related to our equity NGL sales and lower system management gas sales.

Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments reflected within Total revenues primarily in our Gas & NGL Marketing Services, West, and Other segments (see Note 8 – Commodity Derivatives of Notes to Consolidated Financial Statements).

Management’s Discussion and Analysis (Continued)			Table of Contents

Product costs decreased primarily due to lower prices and volumes associated with our NGL marketing activities, lower prices associated with NGLs acquired as commodity consideration related to our equity NGL production activities, and lower system management gas purchases.

Net processing commodity expenses increased primarily due to the unfavorable changes related to gains and losses on commodity derivatives for processing plant shrink gas purchases (see Note 8 – Commodity Derivatives of Notes to Consolidated Financial Statements), partially offset by lower prices and volumes for natural gas purchases associated with our equity NGL production activities.

Operating and maintenance expenses increased primarily due to higher operating costs, including increased costs associated with the 2023 MountainWest Acquisition, the 2022 Trace Acquisition, and the 2022 NorTex Asset Purchase, and increased scope and timing of operating and maintenance activities.

Depreciation and amortization expenses increased primarily related to our upstream assets, and assets acquired in the 2023 MountainWest Acquisition, the 2022 Trace Acquisition, and the NorTex Asset Purchase. The increase is partially offset by lower amortization of intangibles related to our 2021 Sequent Acquisition and a decrease in ARO-related depreciation at Transco (offset in Other (income) expense – net within Operating income (loss) resulting in no net impact on our results of operations).

Selling, general, and administrative expenses increased primarily due to acquisition and transition-related costs associated with the MountainWest Acquisition, partially offset by lower employee-related costs.

Gain on sale of business reflects a gain from the sale of various Gulf Coast petrochemical and feedstock pipelines in our Transmission & Gulf of Mexico segment, as previously discussed.

Other (income) expense – net within Operating income (loss) changed favorably primarily due to the absence of a 2022 loss related to Eminence storage cavern abandonments, a favorable change associated with regulatory liabilities established for the impacts of deferred income taxes at Northwest Pipeline and the absence of 2022 regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate, as well as a 2023 gain related to a contract settlement. These favorable changes were partially offset by a decrease in the deferral of ARO-related depreciation (offset in Depreciation and amortization expenses, resulting in no net impact on our results of operations).

The change in Equity earnings (losses) resulted primarily from a decrease at Laurel Mountain and our share of a loss contingency accrual related to our 14 percent ownership in Aux Sable Liquid Products LP, partially offset by increases at RMM, OPPL, and Blue Racer.

Other investing income (loss) – net changed favorably due to higher interest income earned on higher cash and cash equivalent balances.

Interest expense changed unfavorable primarily due to our 2023 debt issuances and MountainWest's long-term debt (see Note 6 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements), partially offset by an increase in Interest capitalized related to ongoing expansion projects.

The favorable change in Other income (expense) – net below Operating income (loss) includes an increase in equity AFUDC.

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income, the absence of a benefit related to the release of valuation allowances on deferred income tax assets in 2022, a lower benefit associated with decreases in our estimate of the state deferred income tax rate in both periods, and the absence of 2022 federal income tax settlements. See Note 5 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

Income (loss) from discontinued operations in 2023 includes a pre-tax charge of $116 million to increase the related accrued liability associated with our Alaska refinery contamination litigation, partially offset by the related income tax effect (see Note 9 – Contingencies of Notes to Consolidated Financial Statements).

Management’s Discussion and Analysis (Continued)			Table of Contents

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

Period-Over-Period Operating Results - Segments

We evaluate segment operating performance based upon Modified EBITDA. Note 10 – Segment Disclosures of Notes to Consolidated Financial Statements 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,
			2023						2022						2023						2022
			(Millions)
Service revenues			$	978					$	910					$	2,874					$	2,651
Service revenues – commodity consideration (1)			11						11						29						54
Product sales (1)			63						121						197						334
Net realized gain (loss) on commodity derivatives (1)			1						—						2						—
Net unrealized gain (loss) on commodity derivatives			—						1						—						1
Net gain (loss) on commodity derivatives			1						1						2						1
Segment revenues			1,053						1,043						3,102						3,040
Product costs (1)			(64)						(120)						(193)						(329)
Net processing commodity expenses (1)			(4)						(2)						(10)						(23)
Other segment costs and expenses			(286)						(333)						(855)						(844)
Gain on sale of business			130						—						130						—
Proportional Modified EBITDA of equity-method investments			52						50						153						143
Transmission & Gulf of Mexico Modified EBITDA			$	881					$	638					$	2,327					$	1,987
Commodity margins			$	7					$	10					$	25					$	36

(1)Included as a component of Commodity margins.

Three months ended September 30, 2023 vs. three months ended September 30, 2022

Transmission & Gulf of Mexico Modified EBITDA increased primarily due to a Gain on sale of business, higher Service revenues and lower Other segment costs and expenses.

Service revenues increased primarily due to:

• A $62 million increase due to the acquisition of MountainWest in February 2023 primarily in transportation and storage revenues;

• An $11 million increase due to the NorTex Asset Purchase in August 2022 primarily in storage and transportation revenues;

Management’s Discussion and Analysis (Continued)			Table of Contents

• A $5 million increase in the Eastern Gulf Coast region primarily due to higher production handling volumes from new wells at Devils Tower; partially offset by

*•*An $8 million decrease in reimbursable electric power costs, offset by similar changes in electricity charges, reflected in Other segment costs and expenses.

Other segment costs and expenses decreased primarily due to:

• Favorable changes associated with the absence of 2022 regulatory charges associated with decreases in Transco’s estimated deferred state income tax rates and regulatory liabilities established for the impacts of deferred income taxes at Northwest Pipeline;

• The absence of losses related to Eminence storage cavern abandonments in 2022;

• A favorable change in equity AFUDC as a result of increased capital expenditures at Transco; partially offset by

*•*Higher operating and administrative costs including higher operating, acquisition, and transition costs related to our MountainWest Acquisition and NorTex Asset Purchase; and higher costs related to timing and scope of general maintenance activities primarily at Transco and Northwest Pipeline, partially offset by lower reimbursable electric power costs, which is offset by a similar change in electricity reimbursements reflected in Service revenues; and lower employee related costs;

• Higher project feasibility costs.

Gain on sale of business includes a gain recognized on the sale of various petrochemical and feedstock pipelines and associated contracts in the Gulf Coast region in September 2023.

Nine months ended September 30, 2023 vs. nine months ended September 30, 2022

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

Service revenues increased primarily due to:

• A $155 million increase due to the acquisition of MountainWest primarily in transportation and storage revenues;

• A $39 million increase due to the NorTex Asset Purchase primarily in storage and transportation revenues;

• A $23 million increase in the Eastern Gulf Coast region primarily due to higher production handling volumes from new wells at Devils Tower;

• A $17 million increase in Transco’s and Northwest Pipeline’s revenues associated with park and loan services;

• A $13 million increase in Transco’s and Northwest Pipeline’s revenues associated with short term firm transportation; partially offset by

*•*A $10 million decrease in reimbursable electric power costs, offset by similar changes in electricity charges, reflected in Other segment costs and expenses;

*•*A $11 million decrease due to lower rates from the FERC rate case settlement effective January 1, 2023, at Northwest Pipeline.

Management’s Discussion and Analysis (Continued)			Table of Contents

Commodity margins decreased primarily due to a $14 million decrease from our equity NGLs, driven by unfavorable net realized pricing for equity NGL sales.

Other segment costs and expenses increased primarily due to:

*•*Higher operating and administrative costs including higher operating, acquisition, and transition costs related to our MountainWest Acquisition and NorTex Asset Purchase; and higher costs related to timing and scope of general maintenance activities primarily at Transco, partially offset by lower reimbursable electric power costs, which is offset by a similar change in electricity reimbursements reflected in Service revenues; and lower employee-related costs;

• Higher project feasibility costs;

• An unfavorable change in the deferral of ARO-related depreciation at Transco; partially offset by

• Favorable changes associated with regulatory liabilities established for the impacts of deferred income taxes at Northwest Pipeline and the absence of 2022 regulatory charges associated with decreases in Transco’s estimated deferred state income tax rate;

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

• The absence of losses related to Eminence storage cavern abandonments in 2022.

Gain on sale of business includes a gain recognized on the sale of various petrochemical and feedstock pipelines and associated contracts in the Gulf Coast region in September 2023.

Northeast G&P

			Three Months Ended September 30,												Nine Months Ended September 30,
			2023						2022						2023						2022
			(Millions)
Service revenues			$	478					$	417					$	1,421					$	1,208
Service revenues – commodity consideration (1)			—						2						3						12
Product sales (1)			27						40						104						110
Segment revenues			505						459						1,528						1,330
Product costs (1)			(19)						(39)						(96)						(110)
Net processing commodity expenses (1)			(1)						—						—						(2)
Other segment costs and expenses			(150)						(138)						(414)						(392)
Proportional Modified EBITDA of equity-method investments			119						182						421						506
Northeast G&P Modified EBITDA			$	454					$	464					$	1,439					$	1,332
Commodity margins			$	7					$	3					$	11					$	10

(1)Included as a component of Commodity margins.

Three months ended September 30, 2023 vs. three months ended September 30, 2022

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

Service revenues increased primarily due to:

*•*A $25 million increase in gathering revenues in the Utica Shale region primarily related to higher rates resulting from annual cost of service rate redetermination as well as higher volumes;

Management’s Discussion and Analysis (Continued)			Table of Contents

*•*A $20 million increase in revenues at the Northeast JV primarily related to higher transportation & fractionation and processing volumes as well as higher processing rates;

• A $17 million increase in gathering revenues at Susquehanna Supply Hub primarily related to escalated rates as well as higher volumes.

Other segment costs and expenses increased primarily due to increased scope of operations and higher operating taxes.

Proportional Modified EBITDA of equity-method investments decreased due to our $31 million share of a loss contingency accrual related to our 14 percent ownership in Aux Sable Liquid Products LP, as well as a decrease at Laurel Mountain primarily due to lower commodity-based rates, MVC, and volumes. Additionally, for Appalachia Midstream Investments, lower gathering rates resulting from annual cost of service rate redetermination and lower volumes at the Bradford Supply Hub were substantially offset by higher volumes and annual rate escalation at Marcellus South.

Nine months ended September 30, 2023 vs. nine months ended September 30, 2022

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

Service revenues increased primarily due to:

*•*A $90 million increase in revenues at the Northeast JV primarily related to higher transportation & fractionation, processing, and gathering volumes as well as higher processing rates;

• An $84 million increase in gathering revenues in the Utica Shale region primarily related to higher rates resulting from annual cost of service rate redetermination as well as higher volumes;

• A $40 million increase in gathering revenues at Susquehanna Supply Hub primarily related to escalated rates as well as higher volumes.

Other segment costs and expenses increased primarily due to increased scope of operations and higher operating taxes.

Proportional Modified EBITDA of equity-method investments decreased due to lower commodity-based rates, MVC, and volumes at Laurel Mountain, as well as our $31 million share of a loss contingency accrual related to our 14 percent ownership in Aux Sable Liquid Products LP. The decrease was partially offset by an increase at Blue Racer primarily driven by higher volumes. Additionally, Appalachia Midstream Investments increased primarily driven by higher volumes and annual rate escalation at Marcellus South, partially offset by lower gathering rates resulting from annual cost of service rate redetermination and lower volumes at the Bradford Supply Hub.

Management’s Discussion and Analysis (Continued)			Table of Contents

West

			Three Months Ended September 30,												Nine Months Ended September 30,
			2023						2022						2023						2022
			(Millions)
Service revenues			$	374					$	425					$	1,088					$	1,139
Service revenues – commodity consideration (1)			34						47						76						157
Product sales (1)			112						245						287						684
Net realized gain (loss) on commodity derivatives – service revenues			12						(10)						80						(15)
Net realized gain (loss) on commodity derivatives – product sales (1)			1						1						5						(8)
Net realized gain (loss) on commodity derivatives			13						(9)						85						(23)
Segment revenues			533						708						1,536						1,957
Product costs (1)			(108)						(238)						(277)						(667)
Net processing commodity expenses (1)			(18)						(28)						(76)						(91)
Other segment costs and expenses			(137)						(146)						(373)						(413)
Proportional Modified EBITDA of equity-method investments			45						41						121						99
West Modified EBITDA			$	315					$	337					$	931					$	885
Commodity margins			$	21					$	27					$	15					$	75
_________
(1) Included as a component of Commodity margins.

Three months ended September 30, 2023 vs. three months ended September 30, 2022

West Modified EBITDA decreased primarily due to lower Service revenues, partially offset by favorable Net realized gain (loss) on commodity derivatives – service revenues.

Service revenues decreased primarily due to:

• A $48 million decrease in the Barnett Shale region primarily due to lower gathering rates driven by unfavorable commodity pricing; partially offset by

• A $5 million increase in the Haynesville Shale region primarily due to higher gathering volumes associated with increased producer activity, substantially offset by lower gathering rates driven by unfavorable commodity pricing.

Net realized gain (loss) on commodity derivatives – service revenues reflects a favorable change in settled commodity prices relative to our natural gas hedge positions.

Nine months ended September 30, 2023 vs. nine months ended September 30, 2022

West Modified EBITDA increased primarily due to favorable Net realized gain (loss) on commodity derivatives – service revenues, lower Other segment costs and expenses, and higher Proportional Modified EBITDA of equity-method investments, partially offset by lower Commodity margins and lower Service revenues.

Management’s Discussion and Analysis (Continued)			Table of Contents

Service revenues decreased primarily due to:

• A $92 million decrease in the Barnett Shale region primarily due to lower gathering rates driven by unfavorable commodity pricing, partially offset by higher gathering volumes from increased producer activity;

• A $10 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenues, partially offset by higher gathering volumes;

• An $8 million decrease in the Piceance region primarily due to lower gathering and processing volumes driven by natural production rate declines;

• A $7 million decrease associated with reimbursable compressor power and fuel purchases primarily due to lower prices, which are offset by similar changes in Other segment costs and expenses; partially offset by

• A $70 million increase in the Haynesville Shale region primarily associated with higher gathering volumes including from increased producer activity and the Trace Acquisition in April 2022, partially offset by lower rates driven by unfavorable commodity pricing.

Net realized gain (loss) on commodity derivatives – service revenues reflects a favorable change in settled commodity prices relative to our natural gas hedge positions.

Commodity margins decreased primarily due to a $44 million decrease from our equity NGLs and a $16 million decrease from other sales activities, both primarily due to lower net realized commodity pricing.

Other segment costs and expenses decreased primarily due to favorable contract settlements in first-quarter 2023, a favorable change in our net imbalance liability due to changes in pricing, lower employee-related costs, the absence of acquisition-related costs associated with the Trace Acquisition in 2022, and lower reimbursable compressor power and fuel purchases which are offset in Service revenues, partially offset by higher operating expenses related to operations acquired in the Trace Acquisition and unfavorable changes in system gains and losses.

Proportional Modified EBITDA of equity-method investments increased primarily due to higher volumes at OPPL and RMM.

Management’s Discussion and Analysis (Continued)			Table of Contents

Gas & NGL Marketing Services

			Three Months Ended September 30,												Nine Months Ended September 30,
			2023						2022						2023						2022
			(Millions)
Service revenues			$	—					$	1					$	1					$	2
Product sales (1)			556						884						1,658						2,724
Net realized gain (loss) from derivative instruments (1)			(31)						54						41						(18)
Net unrealized gain (loss) from derivative instruments			33						(1)						494						(357)
Net gain (loss) on commodity derivatives			2						53						535						(375)
Segment revenues			558						938						2,194						2,351
Net unrealized gain (loss) from derivative instruments within Net processing commodity expenses			(9)						6						(43)						17
Product costs (1)			(487)						(899)						(1,398)						(2,544)
Other segment costs and expenses			(19)						(25)						(75)						(73)
Gas & NGL Marketing Services Modified EBITDA			$	43					$	20					$	678					$	(249)
Commodity margins			$	38					$	39					$	301					$	162

---

(1) Included as a component of Commodity margins.

Three months ended September 30, 2023 vs. three months ended September 30, 2022

Gas & NGL Marketing Services Modified EBITDA increased primarily due to a favorable change in Net unrealized gain (loss) from derivative instruments within Segment revenues and Net processing commodity expenses.

Commodity margins reflect:

*•*A $47 million decrease from our natural gas marketing operations including $69 million of lower natural gas transportation capacity marketing margins due to an unfavorable change in net realized pricing spreads, partially offset by $22 million of higher natural gas storage marketing margins primarily due to a $41 million favorable change in lower of cost or net realizable value adjustment, partially offset by an unfavorable change in realized derivative gains (losses); substantially offset by

*•*A $46 million increase in our NGL marketing margins including a favorable change in net realized gains and losses on sale of inventory in 2023 compared to 2022 driven by a favorable change in NGL prices and an $18 million favorable change in lower of cost or net realizable value inventory adjustment.

Net unrealized gain (loss) from 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 2022 is primarily due to a change in forward commodity prices relative to our hedge positions in 2023 compared to 2022.

Nine months ended September 30, 2023 vs. nine months ended September 30, 2022

Gas & NGL Marketing Services Modified EBITDA increased primarily due to a favorable change in Net unrealized gain (loss) from derivative instruments within Segment revenues and Net processing commodity expenses and higher Commodity margins.

Management’s Discussion and Analysis (Continued)			Table of Contents

Commodity margins increased $139 million primarily due to:

*•*A $135 million increase from our natural gas marketing operations including $121 million of higher natural gas storage marketing margins primarily driven by lower cost of storage inventory in the first quarter of 2023 resulting from a fourth-quarter 2022 lower of cost or net realizable value inventory adjustment; a favorable change of $35 million lower of cost or net realizable value adjustment; and the absence of a $15 million charge related to the remaining recognition of a purchase accounting inventory fair value adjustment in 2022. The increase in our natural gas marketing margins also includes $14 million of higher natural gas transportation capacity marketing margins due to favorable net realized pricing spreads.

*•*A $4 million increase in our NGL marketing margins including a $13 million favorable change in lower of cost or net realizable value inventory adjustments, partially offset by an unfavorable change in ethane prices and higher transportation and fractionation fees.

Net unrealized gain (loss) from 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 2022 is primarily due to a change in forward commodity prices relative to our hedge positions in 2023 compared to 2022.

Other

			Three Months Ended September 30,												Nine Months Ended September 30,
			2023						2022						2023						2022
			(Millions)
Service revenues			$	4					$	6					$	12					$	22
Product sales (1)			118						238						303						522
Net realized gain (loss) from derivative instruments (1)			9						(58)						41						(104)
Net unrealized gain (loss) from derivative instruments			(1)						29						(18)						10
Net gain (loss) on commodity derivatives			8						(29)						23						(94)
Segment revenues			130						215						338						450
Other segment costs and expenses			(48)						(75)						(140)						(166)
Proportional Modified EBITDA of equity-method investments			(1)						—						(2)						—
Other Modified EBITDA			$	81					$	140					$	196					$	284
Net realized product sales			$	127					$	180					$	344					$	418

---

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

Three months ended September 30, 2023 vs. three months ended September 30, 2022

Other Modified EBITDA decreased primarily due to lower results from our upstream operations, which included the following, partially offset by lower Other segment costs and expenses:

*•*A $53 million decrease in Net realized product sales primarily due to lower net realized commodity prices, partially offset by higher sales associated with increased production volumes from new wells in our Wamsutter and Haynesville Shale regions;

• A $30 million unfavorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to our hedge positions in 2023 compared to 2022.

Management’s Discussion and Analysis (Continued)			Table of Contents

Other segment costs and expenses decreased primarily due to the absence of an $11 million charge related to an accrual for loss contingency in the third quarter of 2022 and a $9 million favorable change associated with regulatory assets related to the effects of deferred taxes on equity funds used during construction.

Nine months ended September 30, 2023 vs. nine months ended September 30, 2022

Other Modified EBITDA decreased primarily due to lower results from our upstream operations, which included the following, partially offset by lower Other segment costs and expenses:

*•*A $74 million decrease in Net realized product sales primarily due to lower net realized commodity prices, partially offset by higher sales associated with increased production volumes. Higher natural gas production volumes from new wells in our Haynesville Shale region and higher crude oil production volumes from new wells in our Wamsutter region were partially offset by lower natural gas and NGL production volumes in our Wamsutter region driven by the impact of severe winter weather in 2023;

• A $28 million unfavorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to our hedge positions in 2023 compared to 2022;

• An increase in Other segment costs and expenses associated with our upstream operations primarily due to increased production volumes and expenses related to severe winter weather in 2023, partially offset by lower associated ad valorem and production taxes which were impacted by lower commodity prices and lower natural gas and NGL production volumes in our Wamsutter region.

Other segment costs and expenses not associated with our upstream operations decreased primarily due to the absence of an $11 million charge related to an accrual for loss contingency in the third quarter of 2022 and a $15 million favorable change associated with regulatory assets related to the effects of deferred taxes on equity funds used during construction.

Management’s Discussion and Analysis (Continued)			Table of Contents

Management’s Discussion and Analysis of Financial Condition and Liquidity

Outlook

Our growth capital and investment expenditures in 2023 are currently expected to be in a range from $1.6 billion to $1.9 billion, excluding acquisitions discussed below. Growth capital spending in 2023 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business and projects supporting growth in the Haynesville basin, including the Louisiana Energy Gateway project. We also expect to invest capital in the development of our upstream oil and gas properties. 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 2023 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.

In October 2023, we agreed to acquire Cureton Front Range, LLC, whose operations are located in the DJ Basin, for $560 million, subject to working capital and post-closing adjustments. Concurrently, we entered into an agreement to purchase an additional 50 percent interest in our equity-method investment RMM for $714 million. Upon closing, we will own 100 percent of and will consolidate RMM. These acquisitions are expected to close in the fourth quarter of 2023 and will expand our gathering and processing footprint in the DJ Basin. The Cureton Front Range, LLC acquisition is expected to be funded with available sources of short-term liquidity. Substantially all of the RMM purchase price is not due to the seller and does not accrue interest until the fourth quarter of 2024.

On September 29, 2023, we completed the sale of various petrochemical and feedstock pipelines and associated contracts in the Gulf Coast region for $348 million (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).

On February 14, 2023, we closed on the acquisition of 100 percent of MountainWest which includes FERC-regulated interstate natural gas pipeline systems and natural gas storage capacity, for $1.08 billion of cash, funded with available sources of short-term liquidity, and retaining $430 million outstanding principal amount of MountainWest long-term debt (see Note 3 – Acquisitions and Divestitures of Notes to Consolidated Financial Statements).

During the first quarter of 2023, we issued $1.5 billion of long-term debt, a portion of which we used to pay down our commercial paper outstanding. During the third quarter of 2023, we issued $1.25 billion of long-term debt. We intend to use the net proceeds from this issuance for general corporate purposes, which may include the repayment of our near-term debt maturities. As of September 30, 2023, we have approximately $2.88 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.

Management’s Discussion and Analysis (Continued)			Table of Contents

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 2023. 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 September 30, 2023, we have $22.8 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, 2023, we had a working capital deficit of $1.3 billion, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:

Available Liquidity			September 30, 2023
			(Millions)
Cash and cash equivalents			$	2,074
Capacity available under our $3.75 billion credit facility, less amounts outstanding under our $3.5 billion commercial paper program (1)			3,750
			$	5,824

(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, 2023. Through September 30, 2023, the highest amount outstanding under our commercial paper program and credit facility during 2023 was $730 million. At September 30, 2023, we were in compliance with the financial covenants associated with our credit facility.

Management’s Discussion and Analysis (Continued)			Table of Contents

Dividends

We increased our regular quarterly cash dividend to common stockholders by approximately 5.3 percent from the $0.425 per share paid in each quarter of 2022, to $0.4475 per share paid in March, June, and September 2023.

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						Stable						BBB
Moody’s Investors Service						Stable						Baa2
Fitch Ratings						Stable						BBB

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)			Table of Contents

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						2023						2022
									(Millions)
Sources of cash and cash equivalents:
Net cash provided (used) by operating activities			Operating						$	4,125					$	3,670
Proceeds from long-term debt			Financing						2,754						1,752
Proceeds from sale of business (see Note 3)			Investing						348						—
Uses of cash and cash equivalents:
Capital expenditures			Investing						(1,845)						(1,447)
Common dividends paid			Financing						(1,635)						(1,553)
Purchases of businesses, net of cash acquired (see Note 3)			Investing						(1,024)						(933)
Proceeds from (payments of) commercial paper - net			Financing						(352)						—
Purchases of treasury stock			Financing						(130)						(9)
Dividends and distributions paid to noncontrolling interests			Financing						(174)						(141)
Purchases of and contributions to equity-method investments			Investing						(80)						(140)
Payments of long-term debt			Financing						(21)						(2,019)
Other sources / (uses) – net			Financing and Investing						(44)						(1)
Increase (decrease) in cash and cash equivalents									$	1,922					$	(821)

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 derivative instruments, Gain on sale of business, Inventory write-downs, and Amortization of stock-based awards.

Our Net cash provided (used) by operating activities for the nine months ended September 30, 2023, increased from the same period in 2022 primarily due to higher operating income (excluding noncash items as previously discussed), net favorable changes in operating working capital, and improved derivative margin requirements, partially offset by lower Distributions from equity-method investees.