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Item 7. Management’s Discussion and Analysis

2024-02-21 compared with 2023-02-27 · 278 added, 187 removed, 360 unchanged (56% of the section changed)

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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.

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, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources.

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 and Northwest Pipeline, 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 consolidated variable interest entity, or VIE), a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery.

• 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 our Northeast JV (a consolidated VIE) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated VIE) 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.

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.

• 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.

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 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.

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Net income (loss) attributable to The Williams Companies, Inc.

for the year ended December 31, 2022, increased by $532 million over the prior year.

for the year ended December 31, 2023, increased by $1.13 billion over the prior year.

Further discussion of our results is found in this report in the Results of Operations.

Recent Developments

Expansion Project Updates

Significant expansion project updates for the period, including projects placed into service are described below.

Ongoing major expansion projects are discussed later in Company Outlook.

Northeast G&P

Susquehanna Supply Hub Gathering Expansion

We have an agreement in place with a third party for a construction project to facilitate natural gas production growth in the Susquehanna region.

We constructed approximately 22 miles of gathering pipeline and associated incremental compression.

The system added incremental natural gas gathering capacity of 320 MMcf/d.

This project went into service in the fourth quarter of 2023.

Utica Shale Gathering Expansion

We have an agreement in place with a third party for a construction project to facilitate natural gas production growth in the Utica region on our Cardinal gathering system.

We constructed approximately 30 miles of gathering pipeline and associated incremental compression.

The system added incremental natural gas gathering capacity of 125 MMcf/d.

Phase 1 of this project was placed into service in the third quarter of 2023 and Phase 2 went into service in the fourth quarter of 2023.

Transmission & Gulf of Mexico

Regional Energy Access

In January 2023, we received approval from the FERC for the project to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in northeastern Pennsylvania to multiple delivery points in Pennsylvania, New Jersey, and Maryland.

We placed approximately half of the project into service in the fourth quarter of 2023 and 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.

Acquisitions and Divestitures (see Note 3 – Acquisitions and Divestitures)

Gulf Coast Storage Acquisition

On January 3, 2024, we closed on the acquisition of 100 percent of a strategic portfolio of natural gas storage facilities and pipelines, located in Louisiana and Mississippi, from Hartree Partners LP for $1.95 billion, subject to working capital and post-closing adjustments.

The purpose of this acquisition was to expand our natural gas storage footprint in the Gulf Coast region, and will be reported in the Transmission & Gulf of

Mexico segment.

The Gulf Coast Storage Acquisition was funded with cash on hand and $100 million of deferred consideration.

DJ Basin Acquisitions

On November 30, 2023, we closed on the acquisition of 100 percent of Cureton, whose operations are located in the DJ Basin, for $546 million, subject to working capital and post-closing adjustments.

Concurrently, we closed on the acquisition of an additional 50 percent interest in our equity-method investment RMM for $704 million.

We now own 100 percent of and consolidate RMM.

The purpose of these acquisitions was to expand our gathering and processing footprint in the DJ Basin.

The Cureton Acquisition was funded with cash on hand.

Substantially all of the RMM purchase price is not due to the seller until the first quarter of 2025, does not accrue interest until the fourth quarter of 2024, and may be repaid early without penalty.

These businesses are 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 $129 million in 2023 in our Transmission & Gulf of Mexico segment.

MountainWest Acquisition

On February 14, 2023, we closed on the acquisition of 100 percent of MountainWest Pipelines Holding Company (MountainWest) which includes FERC-regulated interstate natural gas pipeline systems and natural gas storage capacity, for $1.08 billion of cash and assumption of $430 million outstanding principal amount of long-term debt, subject to working capital and post-closing adjustments.

On February 14, 2023, we closed on the acquisition of 100 percent of MountainWest Pipelines Holding Company 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.

The MountainWest Acquisition expands our existing transmission and storage infrastructure footprint into major markets in Utah, Wyoming, and Colorado.

This business is reported within the Transmission & Gulf of Mexico segment.

Favorable Judgment Against Energy Transfer

We have been involved in litigation since 2016 in Delaware Chancery Court with Energy Transfer Equity, L.P.

(Energy Transfer) related to the Agreement and Plan of Merger with Energy Transfer, dated as of September 28, 2015.

On December 29, 2021, the court entered judgment in our favor in the amount of $410 million, plus interest at the contractual rate, and our reasonable attorneys’ fees and expenses.

On September 21, 2022, the Delaware Chancery Court entered a final order and judgment awarding us a termination fee, attorney’s fees, expenses, and interest in the amount of $602 million plus additional interest starting September 17, 2022.

Energy Transfer appealed to the Delaware Supreme Court.

The Delaware Supreme Court held oral argument en banc on July 12, 2023.

On October 10, 2023, the Delaware Supreme Court issued an opinion affirming the Delaware Chancery Court ruling.

On October 25, 2023, Energy Transfer filed a motion for reargument with the Delaware Supreme Court, which was denied.

On November 28, 2023, we received a $627 million payment from Energy Transfer for the final order and judgment.

On the same day, we paid attorney fees which had been incurred on a contingent fee basis.

This resulted in a net gain of $534 million reported as Net gain from Energy Transfer litigation judgment in our Consolidated Statement of Income for the year ended December 31, 2023 (See Note 17 – Contingencies and Commitments).

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 establishes 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.

NorTex Asset Purchase

On August 31, 2022, we purchased a group of assets in north Texas, primarily natural gas storage facilities and pipelines, from NorTex Midstream Holdings, LLC for $424 million.

Trace Acquisition

On April 29, 2022, we closed on the acquisition of 100 percent of Gemini Arklatex, LLC through which we acquired the Haynesville Shale region gas gathering and related assets of Trace Midstream for $972 million.

The purpose of the Trace Acquisition was to expand our footprint into the east Texas area of the Haynesville Shale region, increasing in-basin scale in one of the largest growth basins in the country.

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

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Our business plan for 2024 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, and annual inflation-based rate increases across our gathering and processing business.

We also anticipate increases resulting from the development of our upstream oil and gas properties and a full year of contribution from recently acquired Trace and NorTex assets.

These increases are partially offset by a lower expected commodity price environment.

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 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 2023 are expected to be in a range from $1.40 billion to $1.70 billion, excluding the MountainWest Acquisition.

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.

Our growth capital and investment expenditures in 2024 are expected to be in a 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 segment 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.

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We plan to place the full 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 May 2022, we filed an application with the FERC for the project, which is 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 2024/2025 winter heating season assuming timely receipt of all necessary regulatory approvals.

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.

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.

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Southeast Energy Connector

In August 2022, we filed an application with the FERC for the project, which is 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 first quarter of 2025, assuming timely receipt of all necessary regulatory approvals.

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 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 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 and North Carolina to delivery points in Virginia, North Carolina, South Carolina, Georgia, and Alabama.

We plan to place the project into service as early as the fourth quarter of 2027, assuming timely receipt of all necessary regulatory approvals.

The project is expected to increase capacity by 1,587 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.

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.

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 the third party’s 26,000 acre dedication.

The system, once constructed, will provide natural gas gathering services to the third party.

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

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.

Critical Accounting Estimates

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We have pension and other postretirement benefit plans that require the use of assumptions and estimates to determine the benefit obligations and costs.

These estimates and assumptions involve significant judgement and actual results will likely be different than anticipated.

These estimates and assumptions involve significant judgment and actual results will likely be different than anticipated.

Estimates and assumptions utilized include the expected long-term rates of return on plan assets, discount rates, cash balance interest crediting rate, and employee demographics, including retirement age and mortality.

These assumptions are reviewed annually and adjustments are made as needed.

The assumptions utilized to compute the benefit obligations and costs are shown in Note 7 – Employee Benefit Plans of Notes to Consolidated Financial Statements.

The assumptions utilized to compute the benefit obligations and costs are shown in Note 7 – Employee Benefit Plans.

The following table presents the estimated increase (decrease) in net periodic benefit cost and obligations resulting from a one-percentage-point change in the specific assumption.

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Our expected long-term rate of return on plan assets used for our pension plans was 5.17 percent in 2023.

The 2022 actual return on plan assets for our pension plans was a loss of approximately 9.7 percent.

The 2023 actual return on plan assets for our pension plans was approximately 11.4 percent.

The 10-year average rate of return on pension plan assets through December 2023 was approximately 6.4 percent.

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Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2022.

The results of operations by segment are discussed in further detail following this consolidated overview discussion.

The following table and discussion is a summary of our consolidated results of operations for the three years ended December 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.

Year Ended December 31,

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2022 $ Change

2021* 2021 $ Change

2020* % Change

Service revenues

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2,779 -1,777 -39 % 4,556 +20 — % 4,536

Net gain (loss) on commodity derivatives (387) -239 -161 % (148) -143 NM (5)

Net gain (loss) from commodity derivatives

956 +1,343 NM (387) -239 -161 % (148)

Total revenues

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665 -29 -5 % 636 -78 -14 % 558

Impairment of certain assets — +2 +100 % 2 +180 +99 % 182

Impairment of goodwill — — — % — +187 +100 % 187

Gain on sale of business

(129) +129 NM — — — % —

Other (income) expense – net

28 -14 -100 % 14 +8 +36 % 22

(30) +58 NM 28 -12 -75 % 16

Total costs and expenses

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Equity earnings (losses) 589 -48 -8 % 637 +29 +5 % 608

Impairment of equity-method investments — — — % — +1,046 +100 % (1,046)

Other investing income (loss) – net 16 +9 +129 % 7 -1 -13 % 8

Other investing income (loss) – net 108 +92 NM 16 +9 +129 % 7

Interest expense (1,236) -89 -8 % (1,147) +32 +3 % (1,179)

Net gain from Energy Transfer litigation judgment

534 +534 NM — — — % —

Other income (expense) – net 99 +81 NM 18 +12 +200 % 6

Income (loss) before income taxes 4,405 2,542 2,073

Provision (benefit) for income taxes 425 +86 +17 % 511 -432 NM 79

Provision (benefit) for income taxes 1,005 -580 -136 % 425 +86 +17 % 511

Income (loss) from continuing operations 3,400 2,117 1,562

Income (loss) from discontinued operations (97) -97 NM — — — % —

Net income (loss)

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Net income (loss) attributable to noncontrolling interests

68 -23 -51 % 45 -58 NM (13)

124 -56 -82 % 68 -23 -51 % 45

Net income (loss) attributable to The Williams Companies, Inc.

$ 2,049 +532 +35 % $ 1,517 +1,306 NM $ 211

$ 3,179 +1,130 +55 % $ 2,049 +532 +35 % $ 1,517

* + = Favorable change;

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

Service revenues increased primarily due to higher gathering and processing rates driven by favorable commodity prices and annual contractual rate escalations for certain of our West and Northeast G&P operations, higher volumes including from the Trace Acquisition and NorTex Asset Purchase, higher transportation fee revenues associated with the Leidy South expansion project placed fully in service at Transco in December 2021,

and higher reimbursable electric power costs and storage rates which are substantially offset in Operating and maintenance expenses .

Service revenues increased primarily due to:

• Higher volumes from acquisitions at our Transmission & Gulf of Mexico segment;

• Higher volumes and rates at our Northeast G&P segment;

partially offset by

• Lower rates, partially offset by higher volumes at our West segment.

The net 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 for our reportable segments (excludes Other) comprise our Commodity margins .

Product sales and net realized gains and losses on commodity derivatives at our Other segment, which reflect sales related to our upstream operations, comprise Net realized product sale s.

Service revenues – commodity consideration, which represent payments we receive in the form of commodities for processing services provided, decreased primarily due to lower NGL prices.

Most of these NGL volumes are sold during the month processed and are offset within Product costs below.

The Product sales decrease primarily consists of:

• Lower marketing sales activities at our Gas & NGL Marketing Services segment;

• Lower sales from upstream operations within Other;

• Lower equity NGL sales prices primarily at our West and Transmission & Gulf of Mexico segments;

• Lower system management gas sales primarily at our West and Transmission & Gulf of Mexico segments.

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, West, and Other segments (see Note 16 – 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 portfolio 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 contracts, which is not recognized until the underlying transaction occurs.

The Product costs decrease primarily consists of:

• Lower marketing activities at our Gas & NGL Marketing Services segment;

• Lower costs associated with NGLs acquired as commodity consideration related to our equity NGL production activities;

• Lower system management gas purchases primarily at our West and Transmission & Gulf of Mexico segments.

Net processing commodity expenses increased primarily due to:

• Unfavorable change in unrealized gains and losses from commodity derivatives related to processing plant shrink gas purchases (see Note 16 – Commodity Derivatives);

• Partially offset by lower natural gas purchases due to lower prices associated with our equity NGL production activities primarily at our West and Transmission & Gulf of Mexico segments.

Operating and maintenance expenses increased primarily due to higher operating costs, including increased costs associated with the February 2023 MountainWest Acquisition, the April 2022 Trace Acquisition, and the August 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 February 2023 MountainWest Acquisition, the April 2022 Trace Acquisition, and the August 2022 NorTex Asset Purchase.

The increase is partially offset by lower amortization of intangibles related to our 2021 Sequent Acquisition.

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

Gain on sale of business resulted from our sale of certain liquids pipelines in the Gulf Coast region (see Note 3 – Acquisitions and Divestitures).

Other (income) expense – net within Operating income (loss) changed favorably primarily due to:

• 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;

• The absence of a 2022 loss related to Eminence storage cavern abandonments;

• A 2023 gain related to a contract settlement.

Equity earnings (losses) changed unfavorably primarily due to 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 Blue Racer and OPPL.

The favorable change in Other investing income (loss) – net includes higher interest income earned on higher cash and cash equivalent balances, and a gain on remeasuring our existing equity-method investment in RMM to fair value with the acquisition of the remaining 50 percent ownership (see Note 3 – Acquisitions and Divestitures).

The increase in Interest expense was primarily due to our 2023 debt issuances and MountainWest's long-term debt (see Note 12 – Debt and Banking Arrangements), partially offset by an increase in interest capitalized related to ongoing expansion projects.

The Net gain from Energy Transfer litigation judgment resulted from a favorable ruling on the final order and judgment of our complaint against Energy Transfer (see Note 17 – Contingencies and Commitments).

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

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 6 – Provision (Benefit) for Income Taxes for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

Income (loss) from discontinued operations in 2023 includes a pre-tax charge of $125 million to increase the related accrued liability associated with our Alaska refinery contamination litigation, partially offset by the related income tax effect (see Note 17 – Contingencies and Commitments).

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

Service revenues – commodity consideration increased primarily due to higher NGL prices, partially offset by lower NGL volumes.

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Product sales also increased due to higher sales volumes and prices associated with our upstream operations and system management gas sales, as well as higher prices and lower volumes related to our equity NGL sales activities.

These increases were partially offset by an unfavorable change in natural gas marketing sales primarily due to the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs (see Note 1 – General, Description of Business, and Basis of Presentation of Notes to Consolidated Financial Statements).

These increases were partially offset by an unfavorable change in natural gas marketing sales primarily due to the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).

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, including significant 2022 lower of cost or net realizable value adjustments to our natural gas inventory.

The unfavorable change in Net gain (loss) on commodity derivatives primarily reflects higher net unrealized losses in our Gas & NGL Marketing Services segment, and higher net realized losses related to derivative contracts in our Other segment.

The unfavorable change in Net gain (loss) from commodity derivatives primarily reflects higher net unrealized losses in our Gas & NGL Marketing Services segment, and higher net realized losses related to derivative contracts in our Other segment.

Lower net realized losses at our West segment and a net unrealized gain at our Other segment in 2022 partially offset these impacts.

Product costs decreased primarily due to the impact of netting the 2022 legacy natural gas marketing revenues with the associated costs.

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Product costs also increased due to higher system management gas purchases and higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities.

Net processing commodity expenses decreased primarily due to the impact of a 2022 net unrealized gain on derivatives for processing plant shrink gas purchases and lower volumes for natural gas purchases associated with our equity NGL production activities, partially offset by higher net realized prices.

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— Year-Over-Year Operating Results - Segments for additional discussion of Commodity margins and Net realized product sales on a segment basis.

Net processing commodity expenses decreased primarily due to the impact of a 2022 net unrealized gain from derivatives for processing plant shrink gas purchases and lower volumes for natural gas purchases associated with our equity NGL production activities, partially offset by higher net realized prices.

Operating and maintenance expenses increased primarily due to higher operating and maintenance costs, including $63 million of higher reimbursable electric power and storage costs which are substantially offset in Service revenues.

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Provision (benefit) for income taxes changed favorably primarily due to a benefit associated with a decrease in our estimate of the state deferred income tax rate, a benefit related to the release of a valuation allowance, and federal settlements, partially offset by higher pre-tax income.

See Note 6 – 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.

See Note 6 – Provision (Benefit) for Income Taxes for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

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

Service revenues increased primarily due to higher transportation fee revenues associated with expansion projects placed in service at Transco in 2020 and 2021, higher revenue associated with reimbursable electricity expenses, and higher processing and fractionation revenues in our Northeast G&P segment.

This increase was partially offset by lower volume deficiency fee revenues, lower gathering volumes, and lower deferred revenue amortization.

Service revenues – commodity consideration increased primarily due to higher NGL prices.

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 increased primarily due to higher prices and volumes associated with our natural gas and NGL marketing activities, as well as the inclusion of our recently acquired upstream operations.

This increase also includes higher prices related to our equity NGL sales activities.

These increases were partially offset by negative product marketing sales from operations acquired in the Sequent Acquisition in 2021 (which does not reflect commodity derivative net realized gains discussed below).

Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments.

The unfavorable change primarily reflects net unrealized losses in our Gas & NGL Marketing Services segment, and net realized losses related to derivative contracts in our West and Other segments.

Net realized gains at our Gas & NGL Marketing Services segment partially offset these impacts.

Product costs increased primarily due to higher prices and volumes associated with our natural gas and NGL marketing activities, as well as higher NGL prices associated with volumes acquired as commodity consideration related to our equity NGL production activities.

Net processing commodity expenses increased primarily due to higher prices for natural gas purchases associated with our equity NGL production activities, partially offset by lower volumes.

Operating and maintenance expenses increased primarily due to the inclusion of our recently acquired upstream operations and higher employee-related expenses, which reflect the absence of a 2020 favorable impact of a change in an employee benefit policy and increased incentive compensation costs associated with improved company performance, as well as higher reimbursable electricity expenses.

Depreciation and amortization expenses increased primarily due to the inclusion of our recently acquired upstream operations, reduced estimated useful lives for certain facilities in our West segment decommissioned during 2021, new assets placed in-service at Transco, and the amortization of intangible assets resulting from the Sequent Acquisition.

Selling, general, and administrative expenses increased primarily due to higher employee-related expenses, which reflect increased incentive compensation costs associated with improved company performance, Sequent Acquisition employee-related costs, and the absence of a 2020 favorable impact of a change in an employee benefit policy, partially offset by lower expenses for various corporate costs.

Impairment of certain assets reflects the 2020 impairment of our Northeast Supply Enhancement development project and certain gathering assets in the Marcellus Shale region (see Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Impairment of goodwill reflects the goodwill impairment charge at the Northeast reporting unit in 2020 (see Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Equity earnings (losses) changed favorably primarily due to the absence of the 2020 impairment of goodwill at RMM, increases at Appalachia Midstream Investments, Laurel Mountain, Blue Racer, Aux Sable, and Discovery, partially offset by a decrease at OPPL.

Impairment of equity-method investments reflects the absence of 2020 impairments to various equity-method investments (see Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

The favorable change in Other income (expense) – net below Operating income (loss) reflects the absence of a 2020 charge for a legal settlement associated with former olefins operations and the absence of 2020 write-offs of certain regulatory assets related to cancelled projects, partially offset by the unfavorable impact of a 2021 accrual for a loss contingency.

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income.

See Note 6 – 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.

The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to the absence of our partner’s share of the 2020 goodwill impairment at the Northeast reporting unit.

Year-Over-Year Operating Results – Segments

We evaluate segment operating performance based upon Modified EBITDA .

Note 18 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss) .

Note 18 – 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.

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Product sales (1) 252 404 349

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

Segment revenues 4,150 4,047 3,786

2 unchanged sentences

Other segment costs and expenses (1,157) (1,141) (982)

Impairment of certain assets — (2) (170)

Gain on sale of business

Proportional Modified EBITDA of equity-method investments 205 193 183

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(1) Included as a component of Commodity margins .

Transmission & Gulf of Mexico Modified EBITDA increased primarily due to higher Service revenues and a Gain on sale of business.

Service revenues increased primarily due to:

• A $222 million increase due to the acquisition of MountainWest primarily in transportation and storage revenues;

• A $42 million increase due to the NorTex Asset Purchase primarily in storage and transportation revenues;

• A $30 million increase in the Eastern Gulf Coast region primarily due to higher production handling volumes from new wells at Devils Tower, partially offset by lower volumes from the Norphlet pipeline due to natural decline;

• A $15 million increase in Transco’s revenues associated with the Regional Energy Access expansion project placed partially in-service in the fourth quarter of 2023;

• A $12 million increase in Transco’s and Northwest Pipeline’s revenues associated with short-term firm transportation;

partially offset by

• A $19 million decrease due to lower rates from the FERC rate case settlement effective January 1, 2023, at Northwest Pipeline;

• A $14 million decrease in reimbursable electric power costs and storage rates, offset by similar changes in electricity charges and storage costs, reflected in Other segment costs and expenses;

• A $10 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).

Commodity margins decreased primarily due to a $15 million decrease from our equity NGLs, driven by unfavorable net realized pricing for equity NGL sales, partially offset by lower prices for natural gas purchases associated with our equity NGL production activities.

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 and storage costs, which are offset by a similar change in electricity reimbursements and storage revenues reflected in Service revenues ;

and lower employee-related costs;

• Higher project feasibility costs;

partially offset by

• Favorable changes associated with regulatory liabilities established for the impacts of deferred income taxes at Northwest Pipeline associated with the FERC rate case settlement mentioned above in Service revenues 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 reflects a gain recognized on the sale of certain liquids pipelines in the Gulf Coast region in September 2023 (see Note 3 – Acquisitions and Divestitures).

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

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These increases are partially offset by a favorable change in the deferral of ARO related depreciation at Transco.

Transmission & Gulf of Mexico Modified EBITDA increased primarily due to favorable changes to Impairment of certain assets and Service revenues, partially offset by higher Other segment costs and expenses.

Service revenues increased primarily due to:

• A $135 million increase in Transco’s and Northwest Pipeline’s natural gas transportation and storage revenues primarily associated with expansion projects placed in service in 2020 and 2021, higher reimbursable electric power costs and a cash out surcharge, which are offset by similar changes in electricity and cash out charges, reflected in Other segment costs and expenses ;

• A $21 million increase from the Norphlet pipeline associated primarily with higher deferred revenue amortization and higher volumes;

• An $18 million increase at Perdido primarily driven by higher volumes due to the absence of temporary shut-ins in 2020 related to scheduled maintenance and fewer Western Gulf of Mexico weather-related events;

partially offset by

• A $25 million decrease at Gulfstar One for the Tubular Bells field primarily associated with lower deferred revenue amortization from lower contractually determined maximum daily quantities;

• A $17 million decrease due to lower volumes at Gulfstar One in the Gunflint field due to ongoing producer operational issues, partially offset by the lower temporary shut-ins related to pricing in 2020.

Commodity margins associated with our equity NGLs increased $21 million primarily driven by favorable NGL sales prices.

Other segment costs and expenses increased primarily due to higher incentive and benefit employee-related costs as previously discussed;

higher operating costs, including higher reimbursable electric power costs;

and a cash out surcharge reserve, which are offset by similar changes in electricity and cash out reimbursements, reflected in Service revenues;

and higher operating taxes, partially offset by a favorable change associated with the deferral of asset retirement obligation-related depreciation at Transco.

Impairment of certain assets reflects the absence of the impairment of our Northeast Supply Enhancement development project in 2020 (see Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Proportional Modified EBITDA of equity-method investments increased at Discovery driven by higher NGL sales prices and higher volumes due to the absence of prior year scheduled maintenance.

Northeast G&P

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Other segment costs and expenses (566) (522) (503)

Impairment of certain assets — — (12)

Proportional Modified EBITDA of equity-method investments 574 654 682

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Service revenues increased primarily due to:

• A $92 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 revenues in the Utica Shale region primarily related to higher gathering rates resulting from annual cost of service contract redeterminations and higher volumes, partially offset by the absence of proceeds from the release of an acreage dedication in 2022;

• A $61 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, a loss contingency accrual, and higher operating taxes.

Proportional Modified EBITDA of equity-method investments decreased at Laurel Mountain due to lower commodity-based gathering rates, MVC, and volumes, and at Aux Sable Liquid Products LP primarily due to our $31 million share of a loss contingency accrual related to our 14 percent ownership.

The decrease was partially offset by an increase at Blue Racer primarily driven by higher gathering and processing volumes.

Additionally, Appalachia Midstream Investments increased primarily driven by higher gathering volumes and annual rate escalations at Marcellus South, partially offset by lower gathering rates resulting from annual cost of service contract redeterminations and lower volumes at the Bradford Supply Hub.

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 $64 million increase in revenues at the Northeast JV primarily related to higher gathering, processing, and fractionation volumes as well as higher processing rates;

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The decrease was partially offset by an increase at Laurel Mountain primarily due to higher commodity-based gathering rates.

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

Service revenues increased primarily due to:

• A $27 million increase in revenues associated with reimbursable electricity expenses, which is offset by similar changes in electricity charges, reflected in Other segment costs and expenses;

• A $23 million increase in revenues at the Northeast JV primarily related to higher processing and fractionation volumes, partially offset by lower gathering volumes;

• A $6 million increase in revenues at Susquehanna Supply Hub primarily related to higher gathering rates, partially offset by lower gathering volumes.

Other segment costs and expenses increased primarily due to higher maintenance and operating expenses, including higher electricity charges, as well as higher incentive and benefit employee-related costs as previously discussed.

Impairment of certain assets reflects a $12 million impairment of certain gathering assets in the Marcellus Shale region in 2020 (see Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments primarily driven by higher volumes as well as the absence of our $26 million share of an impairment of certain assets in 2020 that were subsequently sold.

Additionally, there was an increase at Blue Racer primarily due to the favorable impact of increased ownership as well as the absence of our $10 million share of an impairment of certain assets in 2020.

There was also an increase at Laurel Mountain due to higher commodity-based gathering rates as well as the absence of our $11 million share of an impairment of certain assets in 2020 that were subsequently sold and higher MVC revenue, partially offset by lower volumes, and an increase at Aux Sable.

Year Ended December 31,

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Product sales (1) 441 841 643

Net realized gain (loss) on commodity derivatives – service revenues

Net realized gain (loss) on commodity derivatives – product sales (1)

Net realized gain (loss) on commodity derivatives (4) (44) (2)

Net realized gain (loss) from commodity derivatives relating to service revenues

Net realized gain (loss) from commodity derivatives relating to product sales (1)

Net realized gain (loss) from commodity derivatives

Segment revenues 2,135 2,561 2,026

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(1) Included as a component of Commodity margins .

West Modified EBITDA increased primarily due to higher Service revenues and a favorable change in Net realized gain (loss) on commodity derivatives, partially offset by higher Other segment costs and expenses.

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

Service revenues decreased primarily due to:

• A $120 million decrease in the Barnett Shale region primarily due to lower gathering rates driven by unfavorable commodity pricing;

• A $13 million decrease in the Eagle Ford Shale region primarily due to lower MVC revenues, partially offset by escalated gathering rates and higher gathering volumes;

• A $6 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 $69 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;

• A $25 million increase in the DJ Basin region primarily associated with the DJ Basin Acquisitions in November 2023 (see Note 3 – Acquisitions and Divestitures);

• A $15 million increase in our other NGL operations associated with higher storage fees primarily due to a new contract as well as higher fractionation fees primarily due to higher volumes partially offset by lower rates from lower natural gas prices.

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

Commodity margins decreased $68 million primarily due a $46 million decrease from our equity NGLs and a $14 million decrease from other sales activities, both primarily due to lower net realized commodity pricing.

Other segment costs and expenses decreased primarily due to a favorable change in our net imbalance liability due to changes in pricing, favorable contract settlements in first-quarter 2023, lower corporate allocations, and lower reimbursable compressor power and fuel purchases which are substantially offset in Service revenues.

These items were partially offset by higher operating expenses related to operations including those acquired in the Trace Acquisition and the DJ Basin Acquisitions, lower system gains at Wamsutter, and a fourth quarter 2023 write-down of assets held for sale.

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

West Modified EBITDA increased primarily due to higher Service revenues and a favorable change in Net realized gain (loss) from commodity derivatives, partially offset by higher Other segment costs and expenses.

Service revenues increased primarily due to:

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• A $14 million increase associated with higher fractionation fees primarily due to higher fractionation volumes from a new contract;

• A $4 million increase in the Eagle Ford region primarily due to higher MVC revenues, escalated gathering rates, and higher deferred revenue amortization, substantially offset by lower volumes due to decreased producer activity;

• A $4 million increase in the Eagle Ford Shale region primarily due to higher MVC revenues, escalated gathering rates, and higher deferred revenue amortization, substantially offset by lower volumes due to decreased producer activity;

partially offset by

• A $10 million decrease in the Wamsutter region primarily due to lower MVC revenue.

Net realized gain (loss) on commodity derivatives – service revenues changed favorably due to a change in settled commodity prices relative to our hedge positions.

Net realized gain (loss) from commodity derivatives relating to service revenues changed favorably due to a change in settled commodity prices relative to our hedge positions.

Product margins from our equity NGLs increased $6 million primarily due to higher net realized NGL sales prices, partially offset by higher net realized prices for natural gas purchases associated with our equity NGL production activities.

Additionally, volumes of equity NGL sold and natural gas purchased associated with our

equity NGL production activities were lower primarily due to a customer contract change.

Additionally, volumes of equity NGL sold and natural gas purchased associated with our equity NGL production activities were lower primarily due to a customer contract change.

Margins from other sales activities increased $16 million primarily due to higher condensate sales and favorable pricing.

Marketing margins decreased $20 million primarily due to the absence of the favorable impact of Winter Storm Uri in the first quarter of 2021.

Other segment costs and expenses increased primarily due to higher operating expenses related to timing and scope of activities including from operations acquired in the Trace Acquisition, the absence of gains on asset sales in 2021, higher corporate allocations, acquisition-related costs associated with the Trace Acquisition in 2022, and an unfavorable change in our net imbalance liability due to changes in pricing.

2021, higher corporate allocations, acquisition-related costs associated with the Trace Acquisition, and an unfavorable change in our net imbalance liability due to changes in pricing.

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

West Modified EBITDA increased primarily due to higher Commodity margins, partially offset by lower Service revenues .

Service revenues decreased primarily due to:

• A $63 million decrease associated with lower volumes, primarily due to production declines in the Eagle Ford Shale region which impact is substantially offset by recognition of higher MVC revenue (see below);

• A $22 million decrease driven by lower deferred revenue amortization, primary in the Barnett Shale region;

partially offset by

• A $37 million increase associated with higher MVC revenue primarily in the Eagle Ford Shale region, partially offset by lower MVC revenue in the Wamsutter region;

• A $17 million increase in revenues associated primarily with reimbursable compressor power and fuel purchases due to higher prices related to the impact of Winter Storm Uri in the first quarter of 2021, which are offset by similar changes in Other segment costs and expenses;

• A $10 million increase associated with higher net realized gathering and processing rates, primarily in the Barnett Shale and Piceance regions due to higher commodity pricing, along with escalated gathering rates in the Eagle Ford Shale region, partially offset by a decrease in gathering rates in the Haynesville Shale region due to a customer contract change.

Marketing margins increased by $36 million primarily due to favorable changes in net realized natural gas and NGL prices, including the impact of Winter Storm Uri in the first quarter of 2021.

Product margins from our equity NGLs increased by $13 million, primarily due to favorable net realized commodity price changes, partially offset by lower sales volumes.

Margins on other sales of products increased $12 million primarily due to higher commodity prices.

Other segment costs and expenses increased primarily due to higher incentive and benefit employee-related expenses as previously discussed, higher reimbursable compressor power and fuel purchases which are offset in Service revenues, and higher compressor and plant fuel expenses which are not reimbursable, partially offset by gains on asset sales in 2021, lower leased compressor expenses, favorable changes in system gains and losses, lower legal and consulting expenses, and favorable settlements.

Proportional Modified EBITDA of equity-method investments decreased primarily due to lower volumes at OPPL, partially offset by higher volumes and commodity prices at Brazos Permian II.

Gas & NGL Marketing Services

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Product sales (1) 2,060 3,534 4,292

Net realized gain (loss) from derivative instruments (1) 17 25 (3)

Net unrealized gain (loss) from derivative instruments (321) (109) —

Net gain (loss) on commodity derivatives (304) (84) (3)

Net realized gain (loss) from commodity derivative instruments (1)

Net unrealized gain (loss) from commodity derivative instruments

702 (321) (109)

Net gain (loss) from commodity derivatives

817 (304) (84)

Segment revenues 2,878 3,233 4,211

Net unrealized gain (loss) from derivative instruments within Net processing commodity expenses 47 — —

Net unrealized gain (loss) from commodity derivative instruments within Net processing commodity expenses

Product costs (1) (1,786) (3,228) (4,152)

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(1) Included as a component of Commodity margins .

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

Commodity margins increased $66 million primarily due to:

• A $65 million increase from our natural gas marketing operations including $129 million of higher natural gas storage marketing margins primarily driven by a favorable change of $111 million in 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 was partially offset by $64 million of lower natural gas transportation capacity marketing margins due to less favorable net realized pricing spreads;

• A $1 million increase in our NGL marketing margins including a $20 million favorable change in lower of cost or net realizable value inventory adjustments, partially offset by higher transportation and fractionation fees and an unfavorable change in net realized gains and losses on sale of inventory in 2023 compared to 2022 driven by an unfavorable change in NGL prices.

Net unrealized gain (loss) from commodity derivative instruments within Segment revenues and Net processing commodity expenses relates to derivative contracts that are not designated as hedges for accounting purposes.

The change from 2022 is primarily due to a change in forward commodity prices relative to our hedge positions in 2023 compared to 2022.

Gas & NGL Marketing Services Modified EBITDA decreased primarily due to higher net unrealized loss from derivative instruments and higher Other segment costs and expenses , partially offset by higher Commodity margins .

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• A $30 million decrease in our NGL marketing margins primarily due to lower of cost or net realizable value inventory adjustments in 2022.

Net unrealized gain (loss) from derivative instruments changed primarily due to the Sequent Acquisition in July 2021, and a change in forward commodity prices relative to our hedge positions in 2022 compared to 2021.

Net unrealized gain (loss) from commodity derivative instruments changed primarily due to the Sequent Acquisition in July 2021, and a change in forward commodity prices relative to our hedge positions in 2022 compared to 2021.

Other segment costs and expenses increased primarily due to higher employee-related costs related to the Sequent Acquisition and higher corporate allocations.

Gas & NGL Marketing Services Modified EBITDA decreased primarily due to higher net unrealized losses from derivative instruments, lower Service revenues , and higher segment costs and expenses, partially offset by higher Commodity margins.

Service revenues decreased due to the absence of a temporary volume deficiency fee associated with reduced volumes from a shipper on OPPL in 2020.

Commodity margins increased $135 million primarily due to:

• A $112 million increase associated with our legacy natural gas and NGL marketing operations primarily due to favorable changes in net realized natural gas prices, including the impact of Winter Storm Uri in the first quarter of 2021;

• A $23 million increase associated with the operations acquired in the Sequent Acquisition in 2021 including $35 million primarily related to favorable pricing spreads on transportation capacity reflecting losses on physical transaction settlements more than offset by net realized gains on derivatives.

The transportation related margin was partially offset by a $12 million unfavorable margin related to storage activity.

The unfavorable storage margin reflects gains on physical transaction settlements offset by an $18 million charge related to the partial recognition of a purchase accounting inventory fair value adjustment which increased the weighted-average cost of inventory and $13 million related to a lower of cost or net realizable value inventory adjustment.

The Net unrealized gain (loss) from derivative instruments changed primarily due to the Sequent Acquisition in July 2021, and a change in forward commodity prices relative to our hedge positions.

Other segment costs and expenses increased primarily due to employee-related costs associated with the operations acquired in the Sequent Acquisition in 2021.

Year Ended December 31,

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Product sales (1) 442 706 333

Net realized gain (loss) from derivative instruments (1) (104) (20) —

Net unrealized gain (loss) from derivative instruments 25 — —

Net gain (loss) on commodity derivatives (79) (20) —

Net realized gain (loss) from commodity derivative instruments (1)

47 (104) (20)

Net unrealized gain (loss) from commodity derivative instruments

Net gain (loss) from commodity derivatives

Segment revenues 506 651 345

Other segment costs and expenses (197) (217) (167)

Net gain from Energy Transfer litigation judgment

Proportional Modified EBITDA of equity-method investments

Other Modified EBITDA $ 841 $ 434 $ 178

2 unchanged sentences

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

Other Modified EBITDA increased primarily due to the Net gain from Energy Transfer litigation judgmen t (see Note 17 – Contingencies and Commitments), partially offset by lower results from our upstream operations, which included the following:

• $113 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 $24 million unfavorable change in Net unrealized gain (loss) from commodity derivative instruments due to a change in forward commodity prices relative to our hedge positions in 2023 compared to 2022;

partially offset by

• 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 $19 million favorable change associated with regulatory assets related to the effects of deferred taxes on equity funds used during construction.

Other Modified EBITDA increased primarily due to $248 million higher results from our upstream operations which included the following:

• A $289 million increase in Net realized product sales primarily due to higher commodity prices in 2022, partially offset by the absence of the favorable impact of Winter Storm Uri in 2021 and an unfavorable change in Net realized gain (loss) from derivative instruments due to an increase in commodity prices relative to our hedge positions and an increase in the volume of production hedged in 2022 compared to 2021.

• A $289 million increase in Net realized product sales primarily due to higher commodity prices in 2022, partially offset by the absence of the favorable impact of Winter Storm Uri in 2021 and an unfavorable change in Net realized gain (loss) from commodity derivative instruments due to an increase in commodity prices relative to our hedge positions and an increase in the volume of production hedged in 2022 compared to 2021.

Net realized product sales also increased due to higher production from new wells and higher volumes associated with acquisitions of additional ownership interests in 2021;

• A $25 million favorable change in Net unrealized gain (loss) from derivative instruments due to a change in forward commodity prices relative to our hedge positions and an increase in the volume of production hedged in 2022 compared to 2021;

• A $25 million favorable change in Net unrealized gain (loss) from commodity derivative instruments due to a change in forward commodity prices relative to our hedge positions and an increase in the volume of production hedged in 2022 compared to 2021;

partially offset by

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Other segment costs and expenses also includes an $11 million charge related to an accrual for loss contingency in 2022, substantially offset by the absence of a $10 million charge related to an accrual for loss contingency in 2021.

Other Modified EBITDA increased primarily due to:

• A $168 million increase related to our upstream operations, including the favorable commodity price impact of Winter Storm Uri in the first quarter of 2021;

• A $24 million increase due to the absence of a 2020 charge related to a legal settlement associated with our former olefins operations;

• A $15 million increase due to the absence of 2020 charges related to write-offs of certain regulatory assets associated with cancelled projects;

partially offset by

• A $10 million decrease associated with a 2021 charge related to a legal settlement.

Management’s Discussion and Analysis of Financial Condition and Liquidity

We have continued to focus on earnings and cash flow growth, while continuing to improve leverage metrics and operating costs metrics.

During 2022, we issued approximately $1.75 billion of new long-term debt primarily to fund current or near-term maturities.

In April 2022, we completed the Trace Acquisition;

and in August 2022, we completed the NorTex Asset Purchase, both of which were funded with available sources of short-term liquidity (see Note 3 – Acquisitions of Notes to Consolidated Financial Statements).

See also the section titled Sources (Uses) of Cash .

Our growth capital and investment expenditures in 2023 are currently expected to be in a range from $1.40 billion to $1.70 billion, excluding the MountainWest Acquisition.

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, meet legal, regulatory, and/or contractual commitments.

We have continued to focus on earnings and cash flow growth, noting significant increases in both net income and cash provided by operating activities.

During 2023, investing and financing expenditures included $2.5 billion of capital expenditures, $1.6 billion of acquisitions including MountainWest and Cureton, and $2.2 billion of dividends paid to common shareholders.

These expenditures were funded in part by $5.9 billion of cash provided by operating activities (which includes a net $534 million related to our favorable Energy Transfer litigation outcome - see Note 17 – Contingencies and Commitments), and cash from borrowing activities of $2.5 billion.

Our financial position also reflects the deferred consideration obligation for the RMM Acquisition (see Note 3 – Acquisitions and Divestitures).

We ended the year with $2.150 billion of Cash and cash equivalents as reported on our Consolidated Balance Sheet.

See also the following section titled Sources (Uses) of Cash .

Our growth capital and investment expenditures in 2024 are currently expected to be in a range from $1.45 billion to $1.75 billion, excluding the Gulf Coast Storage Acquisition for $1.95 billion (see Note 3 – Acquisitions and Divestitures).

We also expect to invest capital in our Other segment ventures.

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 February 14, 2023, we acquired 100 percent of MountainWest which includes FERC-regulated interstate natural gas pipeline systems and natural gas storage capacity, for $1.08 billion of cash and assumption of $430 million outstanding principal amount of long-term debt, subject to working capital and post-closing adjustments.

The acquisition was funded with available sources of short-term liquidity.

As of December 31, 2022, we have approximately $627 million of long-term debt due within one year.

On January 5, 2024, we issued $2.1 billion in long-term debt (see Note 12 – Debt and Banking Arrangements).

As of December 31, 2023, we have approximately $2.337 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.

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At December 31, 2023, we have approximately $23.376 billion of long-term debt due after one year.

See Note 12 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements for the aggregate maturities over the next five years.

See Note 12 – Debt and Banking Arrangements for the aggregate maturities over the next five years.

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.

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We had $725 million of commercial paper outstanding at December 31, 2023.

The highest amount outstanding under our commercial paper program and credit facility during 2022 was $1.219 billion.

The highest amount outstanding under our commercial paper program and credit facility during 2023 was $730 million.

At December 31, 2023, we were in compliance with the financial covenants associated with our credit facility.

See Note 12 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements for additional information on our credit facility and commercial paper program.

See Note 12 – Debt and Banking Arrangements for additional information on our credit facility and commercial paper program.

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 each quarter of 2023.

Registrations

In February 2021, we filed a shelf registration statement as a well-known seasoned issuer.

Prior to the expiration of our shelf registration statement, we anticipate filing a new shelf registration statement as a well-known seasoned issuer.

Distributions from Equity-Method Investees

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In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses.

See Note 8 – Investing Activities of Notes to Consolidated Financial Statements for our more significant equity-method investees.

See Note 8 – Investing Activities for our more significant equity-method investees.

Credit Ratings

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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.

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.

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Sources of cash and cash equivalents:

Operating activities – net Operating $ 4,889 $ 3,945 $ 3,496

Net cash provided (used) by operating activities

Operating $ 5,938 $ 4,889 $ 3,945

Proceeds from long-term debt (see Note 12)

Financing 2,755 1,755 2,155

Proceeds from credit-facility borrowings Financing — — 1,700

Proceeds from commercial paper - net Financing 345 — —

Contributions in aid of construction Investing 12 52 37

Uses of cash and cash equivalents:

Payments of long-term debt (see Note 12)

Proceeds from (payments of) commercial paper - net

Financing 372 345 —

Common dividends paid Financing (2,071) (1,992) (1,941)

Payments on credit-facility borrowings Financing — — (1,700)

Proceeds from sale of business (see Note 3)

Uses of cash and cash equivalents:

Capital expenditures Investing (2,516) (2,253) (1,239)

Common dividends paid Financing (2,179) (2,071) (1,992)

Purchases of businesses, net of cash acquired (see Note 3)

Investing (1,568) (933) (151)

Payments of long-term debt (see Note 12)

Financing (634) (2,876) (894)

Dividends and distributions paid to noncontrolling interests Financing (213) (204) (187)

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Investing (141) (166) (115)

Purchases of treasury stock Financing

Other sources / (uses) – net Financing and Investing (32) (5) 16

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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 , Impairment of goodwill , Impairment of equity-method investments , Impairment of certain assets , Net unrealized (gain) loss from derivative instruments , and Inventory write-downs.

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

Our Net cash provided (used) by operating activities in 2023 increased from 2022 primarily due to higher operating income (excluding noncash items as previously discussed), as well as favorable changes in net operating working capital and margin requirements, partially offset by lower Distributions from equity-method investees .

Our Net cash provided (used) by operating activities in 2022 increased from 2021 primarily due to higher operating income (excluding noncash items as previously discussed), favorable changes in margin requirements, and higher Distributions from equity-method investees , partially offset by net unfavorable changes in net operating working capital.

Our Net cash provided (used) by operating activities in 2021 increased from 2020 primarily due to higher operating income (excluding noncash items as previously discussed), favorable changes in net operating working capital reflecting the absence in 2021 of the Transco rate refund payment made in 2020, and higher distributions from unconsolidated affiliates in 2021, partially offset by unfavorable changes in current and noncurrent derivative assets and liabilities.

Environmental

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own (see Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements).

We are monitoring these sites in a coordinated effort with other potentially responsible parties, the EPA, or other governmental authorities.

We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others.

We are jointly and severally liable along with

unrelated third parties in some of these activities and solely responsible in others.

Current estimates of the most likely costs of such activities are approximately $48 million, all of which are included in Accrued and other current liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet at December 31, 2023.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis