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Item 7. Management’s Discussion and Analysis

2023-02-27 compared with 2022-02-28 · 244 added, 232 removed, 303 unchanged (61% of the section changed)

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We focus on consistently attracting new business by providing highly reliable service to our customers.

These services include natural gas gathering, processing, treating, and compression, NGL fractionation and transportation, crude oil production handling and transportation, marketing services for NGL, crude oil and natural gas, as well as storage facilities.

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 Sequent.

All remaining business activities are included in Other.

As of December 31, 2021, our reportable segments are comprised of the following businesses:

• Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco and Northwest Pipeline, 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), which is a proprietary floating production system, a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery.

• 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 variable interest entity) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated variable interest entity) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 50 percent equity-method investment in Blue Racer (we previously effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent equity-method investment in BRMH until acquiring a controlling interest of BRMH in November 2020 and the remaining interest in September 2021), and Appalachia Midstream Investments, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region.

• 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 northwest Louisiana, and the Mid-Continent region which includes the Anadarko and Permian basins.

This segment also includes NGL and natural gas marketing business (excluding the activities within the Sequent segment described below), 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 interest in Brazos Permian II, LLC (Brazos Permian II).

• Sequent includes the operations of Sequent Energy Management, L.P.

and Sequent Energy Canada, Corp.

acquired on July 1, 2021 (Sequent Acquisition).

Sequent focuses on risk management and the marketing,

trading, storage, and transportation of natural gas for a diverse set of natural gas utilities, municipalities, power generators, and producers, and moves gas to markets through transportation and storage agreements on strategically positioned assets, including our Transco system.

• Other includes our upstream operations and minor business activities that are not reportable segments, as well as corporate operations.

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.

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 also includes natural gas storage facilities and pipelines providing services in north Texas.

• 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.

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 included in Part II, Item 8 of this report.

In December 2022, we paid a regular quarterly dividend of $0.425 per share.

On February 1, 2022, our board of directors approved a regular quarterly dividend of $0.425 per share payable on March 28, 2022.

On January 31, 2023, our board of directors approved a regular quarterly dividend of $0.4475 per share payable on March 27, 2023.

Overview of the Results of Operations

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

for the year ended December 31, 2021, increased by $1.3 billion over the prior year, reflecting $223 million of higher net realized commodity margins, $280 million of increased earnings from equity-method investments, primarily due to the absence of our $78 million share of a 2020 impairment of goodwill at West and higher volumes within Northeast G&P, as well as net realized product sales from upstream operations of $313 million and $106 million of higher transportation fee revenues associated with expansion projects placed in service at Transco in 2020 and 2021.

The improvement over last year was partially offset by $314 million of higher operating and administrative costs, $121 million of higher depreciation and amortization expense, and a $109 million unfavorable impact of 2021 net unrealized losses from commodity derivative instruments at Sequent.

The improvement over last year also reflects the absence of $1.4 billion in pre-tax charges in 2020 related to impairments of equity-method investments, goodwill, and certain assets, of which $65 million was attributable to noncontrolling interests.

The provision for income taxes changed unfavorably by $432 million primarily due to higher pre-tax income.

The Sequent segment includes $109 million of net unrealized losses from commodity derivatives not designated as hedges for accounting purposes.

Sequent can 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.

However, the unrealized fair value measurement gains and losses are generally offset by valuation changes in the economic value of the underlying transportation and storage portfolio, which is not recognized until the underlying transportation and storage transaction occurs.

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

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

Recent Developments

Share Repurchase Program

In September 2021, our Board of Directors authorized a share repurchase program with a maximum dollar limit of $1.5 billion.

Repurchases may be made from time to time in the open market, by block purchases, in privately negotiated transactions, or in such other manner as determined by our management.

Our management will also determine the timing and amount of any repurchases based on market conditions and other factors.

The share repurchase program does not obligate us to acquire any particular amount of common stock, and it may be suspended or discontinued at any time.

This stock repurchase program does not have an expiration date.

There were no repurchases under the program as of December 31, 2021.

Sequent Acquisition

In July 2021, we completed the acquisition of 100 percent of Sequent.

Total consideration for this acquisition was $159 million, which included $109 million related to working capital.

Sequent focuses on risk management and the marketing, trading, storage, and transportation of natural gas for a diverse set of natural gas utilities, municipalities, power generators, and producers, and moves gas to markets through transportation and storage agreements on strategically positioned assets, including our Transco system.

The addition of Sequent complements

the geographic footprint of our core pipeline transportation and storage business, enhances our gas marketing capabilities, and expands the suite of services we provide to our existing midstream customers.

Upstream Joint Ventures

In the third quarter of 2021, we conveyed certain oil and gas properties in the Wamsutter field, which we acquired in 2021, to a venture along with certain oil and gas properties conveyed by a third-party operator in the region.

Under the terms of the agreement, the third party owns a 25 percent and we own a 75 percent undivided interest in each well’s working interest.

We will retain ownership in the undeveloped acreage until certain acreage earning hurdles are met, at which time the remaining undeveloped acreage will be conveyed to the third party resulting in the third party owning 50 percent and us owning 50 percent.

The combined properties consist of over 1.2 million net acres and an interest in over 3,500 wells.

In the third quarter of 2021, we sold 50 percent of certain existing wells and wellbore rights in the South Mansfield area of the Haynesville Shale region to a third party operator, in a strategic effort to develop the acreage, thereby enhancing the value of our midstream natural gas infrastructure.

Under the agreement, the third party will operate the upstream position and develop the undeveloped acreage.

We will retain ownership in the undeveloped acreage until certain acreage earning and carried interest hurdles are met, at which time remaining undeveloped acreage will be conveyed to the third party resulting in the third party owning 75 percent and us owning 25 percent.

Expansion Project Update

Transmission & Gulf of Mexico

In July 2020, we received approval from the FERC for the project to expand Transco’s existing natural gas transmission system and also extend its system through a capacity lease with National Fuel Gas Supply Corporation that will enable us to provide incremental firm transportation from Clermont, Pennsylvania and from the Zick interconnection on Transco’s Leidy Line to the River Road regulating station in Lancaster County, Pennsylvania.

We placed 125 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and in September and October of 2021, we placed approximately 382 Mdth/d of additional capacity into service.

We placed the remainder of the project into service in December 2021.

The project increased capacity by 582 Mdth/d.

Southeastern Trail

In October 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion’s Cove Point Pipeline in Virginia to the Station 65 pooling point in Louisiana.

We placed 230 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and the project was fully in service on January 1, 2021.

In total, the project increased capacity by 296 Mdth/d.

The outbreak of COVID-19 severely impacted global economic activity and caused significant volatility and negative pressure in financial markets.

We continue to monitor the COVID-19 pandemic and have taken steps intended to protect the safety of our customers, employees, and communities, and to support the continued delivery of safe and reliable service to our customers and the communities we serve.

Our financial condition, results of operations, and liquidity have not been materially impacted by effects of COVID-19.

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.

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

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.

Company Outlook

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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 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 2022, our operating results are expected to benefit from growth in our Ohio Valley Midstream, Cardinal, Susquehanna, and Haynesville areas.

We also anticipate increases resulting from recently completed Transco expansion projects and development of our upstream oil and gas properties.

These increases are partially offset by the absence of favorable results captured during Winter Storm Uri in 2021 by our commodity marketing business and lower expected results in the Bradford Supply Hub primarily due to lower gathering rates resulting from annual cost of service contract redetermination.

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.

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 2022 are expected to be in a range from $1.25 billion to $1.35 billion.

Growth capital spending in 2022 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business, opportunities in the Haynesville area, and an expansion in the Western Gulf area.

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.

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 meet legal, regulatory, and/or contractual commitments.

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:

• Continued negative impacts of COVID-19 driving 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;

• 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;

• 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;

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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 March 2021, we filed an application with 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.

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 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.

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 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 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.

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.

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 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.

Critical Accounting Estimates

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Our expected long-term rate of return on plan assets used for our pension plans was 3.81 percent in 2022.

The 2021 actual return on plan assets for our pension plans was approximately 4.9 percent.

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

The 10-year average rate of return on pension plan assets through December 2022 was approximately 6.8 percent.

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4,556 +20 — % 4,536 +2,865 +171 % 1,671

Net gain (loss) on commodity derivatives (148) -143 NM (5) -7 NM 2

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

Total revenues

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3,369 +562 +14 % 3,931 -2,386 -154 % 1,545

Processing commodity expenses

101 -33 -49 % 68 +37 +35 % 105

Net processing commodity expenses 88 +13 +13 % 101 -33 -49 % 68

Operating and maintenance expenses

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

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

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

Other (income) expense – net

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Equity earnings (losses) 637 +29 +5 % 608 +280 +85 % 328

Impairment of equity-method investments — +1,046 +100 % (1,046) -860 NM (186)

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

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

Interest expense (1,147) +32 +3 % (1,179) -7 -1 % (1,172)

Other income (expense) – net 6 +49 NM (43) -76 NM 33

Income (loss) from continuing operations before income taxes

2,073 277 1,064

Other income (expense) – net 18 +12 +200 % 6 +49 NM (43)

Income (loss) before income taxes 2,542 2,073 277

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

Income (loss) from continuing operations 1,562 198 729

Income (loss) from discontinued operations — — — % — +15 +100 % (15)

Net income (loss)

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

$ 1,517 $ 211 $ 850

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

* + = 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 – commodity consideration increased primarily due to higher NGL prices, partially offset by lower NGL 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 increased primarily due to higher marketing sales prices and volumes, including increased volumes associated with the Sequent Acquisition in third-quarter 2021 and the Trace Acquisition in second-quarter 2022.

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).

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.

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

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.

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

This decrease was partially offset by higher prices and volumes associated with our NGL marketing activities, including the increase in volumes associated with the Trace Acquisition in second-quarter 2022, as well as significant 2022 lower of cost or net realizable value adjustments to our NGL inventory.

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.

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 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— Year-Over-Year 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 and maintenance costs, including $63 million of higher reimbursable electric power and storage costs which are substantially offset in Service revenues.

The increase was also a result of higher expenses associated with our upstream operations, increased costs associated with Transco's Leidy South expansion project placed in service in December 2021, higher employee-related expenses, and higher expenses associated with the 2022 Trace Acquisition and NorTex Asset Purchase.

Depreciation and amortization expenses increased primarily due to amortization of intangibles acquired in the Sequent and Trace Acquisitions and an increase in depreciation at Transco related to ARO revisions (offset in Other (income) expense – net within Operating income (loss) resulting in no net impact on our results of operations), partially offset by the absence of 2021 depreciation on certain decommissioned facilities in our West segment.

Selling, general, and administrative expenses increased primarily due to higher employee-related expenses driven by the Sequent Acquisition in July 2021 and higher expenses for various corporate costs, including technology costs to support efforts to track and quantify emissions associated with natural gas procurement, transmission, and delivery.

Other (income) expense – net within Operating income (loss) changed unfavorably primarily due to charges related to Eminence storage cavern abandonments and monitoring, as well as regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate, offset by the deferral of ARO depreciation (offset in Depreciation and amortization expenses resulting in no net impact on our results of operations).

Equity earnings (losses) changed favorably primarily due to increases at investments across our West segment, including RMM, and at Laurel Mountain, partially offset by a decrease at Appalachia Midstream Investments.

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.

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 in our West 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.

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

These increases were partially offset by negative product marketing sales from Sequent (which does not reflect Sequent’s commodity derivative net realized gains discussed below).

As we are acting as agent for our Sequent natural gas marketing customers, our natural gas marketing product sales are presented net of the related product costs of those 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 Sequent segment, and net realized losses related to derivative contracts in our West and Other segments.

Net realized gains at our Sequent segment partially offset these impacts.

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.

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.

The net sum of Service revenues – commodity consideration , Product sales , Product costs, Processing commodity expenses, and net realized gains and losses on commodity derivatives related to sales of product comprise our commodity margins.

However, Product sales at our Other segment reflect sales related to our oil and gas producing properties and are excluded from our commodity margins.

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 (see Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements) and increased incentive compensation costs associated with improved company performance, as well as higher reimbursable electricity expenses.

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 employee-related costs, and the absence of a 2020 favorable impact of a change in an employee benefit policy (see Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements), partially offset by lower expenses for various corporate costs.

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).

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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.

Service revenues decreased primarily due to lower volumes in our West segment, lower deferred revenue amortization at Gulfstar One, the expiration of an MVC agreement in the Barnett Shale region, and temporary shut-ins at certain offshore Gulf of Mexico operations.

This decrease was partially offset by higher Northeast G&P revenues driven by higher volumes and the March 2019 consolidation of UEOM (see Note 3 – Acquisitions of Notes to Consolidated Financial Statements), higher MVC revenue in our West segment, as well as higher transportation fee revenues at Transco and Northwest Pipeline associated with expansion projects placed in service in 2019 and 2020, increased volumes in the Eastern Gulf region, and higher deficiency fee revenue associated with lower volumes at OPPL.

Service revenues – commodity consideration decreased due to lower commodity prices, as well as lower equity NGL processing volumes due to less producer drilling activity.

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 within the month processed and therefore are offset within Product costs below.

Product sales decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL sales activities, as well as lower volumes associated with our equity NGL sales activities, partially offset by higher marketing volumes.

This decrease also includes lower system management gas sales.

Marketing sales and system management gas sales are substantially offset within Product costs .

Product costs decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL production activities.

This decrease also includes lower volumes acquired as commodity consideration for NGL processing services and lower system management gas purchases, partially offset by higher volumes for marketing activities.

Processing commodity expenses decreased primarily due to lower natural gas purchases associated with equity NGL production primarily due to lower natural gas prices and lower volumes .

Operating and maintenance expenses decreased primarily due to lower employee-related expenses, including the absence of 2019 severance and related costs and the associated reduced costs in 2020, as well as the favorable impact of a 2020 change in an employee benefit policy (see Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements), and lower maintenance and operating costs primarily due to timing and scope of activities.

These decreases are partially offset by higher expenses related to the consolidation of UEOM.

Depreciation and amortization expenses increased primarily due to new assets placed in service and the March 2019 consolidation of UEOM, partially offset by lower expense related to assets that became fully depreciated in the fourth quarter of 2019.

Selling, general, and administrative expenses decreased primarily due to lower employee-related expenses, including the absence of 2019 severance and related costs and the associated reduced costs in 2020, as well as the favorable impact of a 2020 change in an employee benefit policy (see Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements), and the absence of transaction costs associated with our 2019 acquisition of UEOM and the formation of the Northeast JV.

Impairment of certain assets includes the 2019 impairments of our Constitution development project, certain Eagle Ford Shale gathering assets, and certain idle gathering assets.

The asset impairments in 2020 included our Northeast Supply Enhancement development project and certain gathering assets in the Marcellus Shale region (see Note 17 – 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 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Equity earnings (losses) changed unfavorably primarily due to our share of 2020 impairments at equity-method investments (see Note 9 – Investing Activities of Notes to Consolidated Financial Statements), and lower volumes at OPPL and Discovery.

These decreases were partially offset by favorable amortization of basis differences related to impairments of several of our equity-method investments which were recognized in first quarter 2020, as well as higher volumes at Appalachia Midstream Investments, increased results at Blue Racer driven by higher volumes and a higher ownership interest, and the absence of 2019 losses at Brazos Permian II.

Impairment of equity-method investments includes impairments to various equity-method investments in 2019 and 2020 (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

The unfavorable change in Other investing income (loss) – net is primarily due to the absence of a 2019 gain on the sale of our equity-method investment in Jackalope, partially offset by the absence of a 2019 loss on the deconsolidation of Constitution (see Note 9 – Investing Activities of Notes to Consolidated Financial Statements).

The unfavorable change in Other income (expense) – net below Operating income (loss) includes a charge in the fourth quarter 2020 for a legal settlement associated with former olefins operations, lower equity allowance for funds used during construction (AFUDC), and 2020 write-offs of certain regulatory assets related to cancelled projects.

Provision (benefit) for income taxes changed favorably primarily due to lower 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 the 2019 impairment of our Constitution development project and the impact from the formation of the Northeast JV in June 2019, partially offset by the first-quarter 2020 goodwill impairment charge at the Northeast reporting unit, and lower Gulfstar One results.

Year-Over-Year Operating Results – Segments

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Product costs (1) (399) (349) (193)

Processing commodity expenses (17) (7) (16)

Net processing commodity expenses (1) (26) (17) (7)

Other segment costs and expenses (1,141) (980) (886)

3 unchanged sentences

Commodity margins $ 43 $ 35 $ 12

_______________

(1) Included as a component of Commodity margins .

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

Service revenues increased primarily due to:

• A $163 million increase in Transco’s service revenues primarily associated with the Leidy South expansion project placed fully in service in December 2021, park and loan services, short-term firm transportation, overall demand, and commodity fee revenues.

Additionally, 2022 benefited from higher reimbursable electric power costs and storage rates effective since the second quarter of 2022, partially offset by lower cash out surcharges, all of which are offset by similar changes in electricity, storage and cash out charges reflected in Other segment costs and expenses;

• A $21 million increase in the Eastern Gulf Coast region primarily due to higher production handling and gathering volumes from the absence of temporary shut-ins due to producer operational issues and weather-related events in 2021, partially offset by a decrease at Gulfstar One for the Tubular Bells field primarily due to lower production handling, gathering and transportation volumes from natural decline;

• A $16 million increase primarily related to storage and transportation revenues due to the acquisition of NorTex in August 2022;

partially offset by

• A $13 million decrease in the Western Gulf Coast region primarily at Perdido due to lower transportation and gathering volumes from temporary downtime from producer operational issues in 2022.

Commodity margins associated with our equity NGLs increased $5 million primarily driven by favorable NGL sales prices, partially offset by higher prices for natural gas purchases associated with our equity NGL production activities.

Other segment costs and expenses increased primarily due to higher operating costs including higher reimbursable electric power costs and storage costs, partially offset by favorable cash out charges, all of which are offset by similar changes in electricity reimbursements, cash out charges, and storage revenues reflected in Service revenues.

Additionally, 2022 was impacted by higher costs associated with the Leidy South expansion project;

maintenance costs primarily related to general maintenance at Transco, Gulf Coast region, and Northwest Pipeline;

charges related to Eminence storage cavern abandonments and monitoring;

and regulatory charges associated with a decrease in Transco’s estimated deferred state income tax rate, higher employee-related costs, corporate allocations, and operations acquired in the NorTex Asset Purchase.

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.

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• 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.

The net sum of Service revenues – commodity consideration , Product sales , Product costs, Processing commodity expenses, comprise our Commodity margins .

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

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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.

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

Service revenues decreased primarily due to:

• A $115 million decrease due to lower deferred revenue amortization associated with the end of the exclusive use period at Gulfstar One for the Tubular Bells field;

• A $42 million decrease due to temporary shut-ins primarily at Perdido and Gulfstar One related to Gulf of Mexico weather-related events, pricing, and scheduled maintenance;

• A $32 million decrease due to lower volumes at Gulfstar One in the Gunflint field due to ongoing operational issues;

partially offset by

• A $65 million increase in Transco’s and Northwest Pipeline’s natural gas transportation revenues associated with expansion projects placed in service in 2019 and 2020;

• A $44 million increase at Gulfstar One associated with higher volumes in the Tubular Bells field due to a new well and higher production;

• A $24 million increase associated with volumes from Norphlet placed in service in June 2019.

Commodity margins associated with our equity NGLs decreased $11 million driven by lower commodity prices and volumes.

Other segment costs and expenses decreased primarily due to lower employee-related expenses, including the absence of 2019 severance and related costs and the associated reduced costs in 2020, as well as the favorable impact of a 2020 change in an employee benefit policy (see Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements), lower maintenance costs primarily due to a decrease in contracted services related to general maintenance and other testing at Transco, the absence of a 2019 charge for reversal of costs capitalized in previous periods.

The 2020 period also benefited from net favorable changes to charges and credits associated with a regulatory asset related to Transco’s asset retirement obligations, partially offset by lower equity AFUDC and higher operating taxes.

Impairment of certain assets includes the absence of the impairment of our Constitution development project in 2019, partially offset by the impairment of our Northeast Supply Enhancement development project in 2020 (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Proportional Modified EBITDA of equity-method investments decreased at Discovery driven by lower volumes due to scheduled maintenance and temporary shut-ins related to Gulf of Mexico weather-related events and pricing.

Northeast G&P

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Product costs (1) (135) (99) (57)

Processing commodity expenses (2) (3) (8)

Net processing commodity expenses (1) (3) (2) (3)

Other segment costs and expenses (522) (503) (441)

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Commodity margins $ 10 $ 5 $ 4

(1) Included as a component of Commodity margins .

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;

• A $43 million increase in revenues in the Utica Shale region primarily related to higher gathering rates resulting from annual cost of service contract redeterminations, as well as proceeds from the release of an acreage dedication;

• A $14 million increase in revenues associated with reimbursable expenses, which is offset by similar changes in the charges reflected in Other segment costs and expenses;

• No change in revenues at Susquehanna Supply Hub primarily related to higher gathering rates, offset by lower gathering volumes.

Other segment costs and expenses increased primarily due to higher operating expenses, including higher electricity and fuel, which is partially offset in Service revenues .

Proportional Modified EBITDA of equity-method investments decreased at Appalachia Midstream Investments primarily driven by lower gathering rates resulting from annual cost of service contract redeterminations as well as lower volumes.

Additionally, there was a decrease at Blue Racer primarily due to lower volumes.

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 .

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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.

Northeast G&P Modified EBITDA increased primarily due to higher Service revenues, lower Other segment costs and expenses, and increased Proportional Modified EBITDA of equity-method investments , in addition to the favorable impact of acquiring the additional interest in UEOM, which is a consolidated entity after the remaining ownership interest was purchased in March 2019.

Service revenues increased primarily due to:

• A $94 million increase at the Northeast JV, including $62 million higher processing, fractionation, transportation, and gathering revenues primarily due to higher volumes and a $32 million increase associated with the consolidation of UEOM, as previously discussed;

• A $20 million increase in gathering revenues associated with higher volumes in the Utica Shale region;

• A $13 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.

Other segment costs and expenses decreased due to lower employee-related expenses, including the absence of 2019 severance and related costs and the associated reduced costs in 2020, as well as the favorable impact of a 2020 change in an employee benefit policy (see Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements), and lower maintenance and operating expenses primarily due to timing and scope of activities.

Additionally, expenses changed favorably due to the absence of transaction costs associated with our 2019 acquisition of UEOM and the formation of the Northeast JV.

These decreases were partially offset by higher reimbursable electricity expenses, increased expenses associated with the consolidation of UEOM, and the absence of a favorable customer settlement in 2019.

Impairment of certain assets reflects a $12 million impairment of certain gathering assets in the Marcellus Shale region in 2020 and a $10 million write-down of other certain assets that were no longer in use or were surplus in nature in 2019 (see Note 17 – 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 driven by higher volumes, partially offset by a $26 million decrease for our share of an impairment of certain assets.

Additionally, there was an increase at Blue Racer primarily due to higher volumes and the favorable impact of increased ownership, partially offset by a $10 million decrease for our share of an impairment of certain assets.

These increases were partially offset by a $16 million decrease as a result of the consolidation of UEOM in 2019, as previously discussed, as well as a decrease at Laurel Mountain primarily due to $11 million for our share of an impairment of certain assets that were subsequently sold, partially offset by higher volumes, and a decrease at Aux Sable.

Year Ended December 31,

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Product sales (1) 841 643 152

Net gain (loss) on commodity derivatives (85) (5) 2

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)

Segment revenues 2,561 2,026 1,523

Product costs (1) (813) (608) (154)

Processing commodity expenses (85) (58) (79)

Net processing commodity expenses (1) (105) (85) (58)

Other segment costs and expenses (564) (477) (474)

Impairment of certain assets — — (100)

Proportional Modified EBITDA of equity-method investments 132 105 110

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Commodity margins $ 102 $ 100 $ 39

Net unrealized gain (loss) from derivative instruments — — 3

________________

(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.

Service revenues increased primarily due to:

• A $186 million increase in the Haynesville Shale region primarily due to higher gathering volumes including volumes from the Trace Acquisition as well as higher gathering rates driven by favorable commodity pricing;

• A $96 million increase in the Barnett Shale region primarily due to higher gathering rates driven by favorable commodity pricing;

• 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;

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.

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.

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.

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 .

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• 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 $29 million decrease due to the absence of a temporary volume deficiency fee from a customer in 2020;

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

1 unchanged sentence

• 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 severe winter weather, which are offset by similar changes in Other segment costs and expenses;

• 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.

The net sum of Service revenues – commodity consideration, Product sales, Product costs, Processing commodity expenses, and net realized gains and losses on commodity derivatives related to sales of product comprise our Commodity margins.

We further segregate our Commodity margins into product margins associated with our equity NGLs and marketing margins.

Marketing margins increased by $145 million primarily due to favorable changes in net realized natural gas and NGL prices, including the impact of severe winter weather 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.

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 decreased primarily due to 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, partially offset by higher reimbursable compressor power and fuel purchases which are offset in Service revenues and higher incentive and benefit employee-related expenses as previously discussed.

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.

West Modified EBITDA increased primarily due to the absence of Impairment of certain assets and lower Other segment costs and expenses, partially offset by lower Service revenues .

Service revenues decreased primarily due to:

• An $83 million decrease associated with lower volumes, excluding the Eagle Ford Shale region;

• A $72 million decrease driven by lower deferred revenue amortization and MVC deficiency fee revenues associated with the second-quarter 2019 expiration of the MVC agreement in the Barnett Shale region;

• A $47 million decrease associated with lower rates, excluding the Eagle Ford Shale region, driven by lower commodity pricing in the Barnett Shale region and the expiration of a cost-of-service period on a contract in the Mid-Continent region;

• An $11 million decrease associated with lower fractionation fees driven by lower volumes;

• An $8 million decrease driven by the absence of a favorable 2019 cost-of-service agreement adjustment in the Mid-Continent region;

partially offset by

• A $91 million increase in the Eagle Ford Shale region due to higher MVC revenue and higher rates, partially offset by lower volumes primarily due to decreased producer activity, including temporary shut-ins on certain gathering systems;

• A $29 million increase associated with a temporary volume deficiency fee associated with reduced volumes from a shipper on OPPL;

• A $26 million increase in the Wamsutter region associated with higher MVC revenues.

Product margins from our equity NGLs decreased $29 million primarily due to:

• A $35 million decrease associated with lower sales prices primarily due to 25 percent lower average net realized per-unit non-ethane sales prices;

• A $15 million decrease primarily associated with 14 percent lower non-ethane sales volumes driven by less producer drilling activity;

partially offset by

• A $21 million increase related to a decline in natural gas purchases associated with equity NGL production due to lower natural gas prices and lower equity non-ethane production volumes.

Additionally, marketing margins increased by $26 million primarily due to higher net realized NGL and natural gas prices.

The decrease in Product sales includes a $168 million decrease in marketing sales, which is due to lower sales prices, partially offset by higher marketing sales volumes.

An $18 million decrease in other product sales also contributed to the overall decrease.

These decreases are substantially offset in Product costs.

Other segment costs and expenses decreased primarily due to lower employee-related expenses driven by the absence of 2019 severance and related costs and the associated reduced costs in 2020, and the favorable impact of a

2020 change in an employee benefit policy (see Note 5 – Other Income and Expenses of Notes to Consolidated Financial Statements), as well as lower operating costs due to fewer leased compressors and lower maintenance costs primarily due to timing and scope of activities.

These favorable changes are partially offset by the absence of $12 million in favorable settlements in 2019.

Impairment of certain assets reflects a $79 million impairment of certain Eagle Ford Shale gathering assets and a $12 million impairment of certain idle gathering assets in 2019 (see Note 17 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements).

Proportional Modified EBITDA of equity-method investments decreased primarily due to lower volumes at OPPL and the absence of the Jackalope equity-method investment sold in April 2019, partially offset by growth at the RMM, Brazos Permian II, and Targa Train 7 equity-method investments.

We closed the Sequent Acquisition on July 1, 2021.

See the Sequent Acquisition section of Recent Developments above for additional information related to Sequent.

Gas & NGL Marketing Services

Year Ended December 31,

2022 2021 2020

Service revenues $ 3 $ 3 $ 32

Product sales (1) 3,534 4,292 1,602

3 unchanged sentences

Segment revenues 3,233 4,211 1,631

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

Product costs (1) (3,228) (4,152) (1,569)

Other segment costs and expenses (92) (37) (11)

Sequent Modified EBITDA $ (112)

Gas & NGL Marketing Services Modified EBITDA $ (40) $ 22 $ 51

Commodity margins $ 323 $ 165 $ 30

Sequent Modified EBITDA reflects Commodity margins more than offset by net unrealized losses from derivative instruments and segment costs and expenses.

The net sum of Product sales and net realized gains and losses on commodity derivatives related to sales of product comprise our Commodity margins .

Commodity margins include $35 million primarily related to favorable pricing spreads on Sequent’s transportation capacity reflecting losses on physical transaction settlements more than offset by net realized gains on derivatives.

________________

(1) Included as a component of Commodity margins .

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 .

Commodity margins increased $158 million primarily due to:

• A $188 million increase in natural gas marketing margins which included the following:

◦ A $301 million increase in natural gas transportation capacity marketing margins primarily resulting from the Sequent Acquisition in the third quarter of 2021 and an increase in favorable pricing spreads in 2022 compared to 2021;

partially offset by

◦ A $58 million decrease associated with our legacy natural gas marketing operations primarily due to the absence of the favorable impact of Winter Storm Uri in the first quarter of 2021;

◦ A $55 million decrease in natural gas storage marketing margins due primarily to an increase in lower of cost or net realizable value inventory adjustments of $115 million and higher storage fees, partially offset by higher storage withdrawals in 2022 compared to 2021.

• 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.

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 relates to derivative contracts within the Sequent segment that are not designated as hedges for accounting purposes.

Other segment costs and expenses primarily include employee-related costs.

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,

2022 2021 2020

Service revenues $ 24 $ 32 $ 34

Product sales (1) 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) —

Segment revenues 651 345 34

Other segment costs and expenses (217) (167) (49)

Other Modified EBITDA $ 434 $ 178 $ (15)

Net realized product sales $ 602 $ 313 $ —

________________

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

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.

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;

partially offset by

• A $66 million increase in Other segment costs and expenses primarily due to the increased scale of our upstream operations and higher associated production taxes which were also impacted by higher commodity prices and higher volumes as well as higher tax rates.

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 due to our recently acquired upstream operations, including the favorable commodity price impact of severe winter weather in the first quarter of 2021;

• 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;

2 unchanged sentences

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

Other Modified EBITDA decreased primarily due to:

• A $24 million charge in fourth quarter of 2020 related to a legal settlement associated with former olefins operations;

• A charge of $15 million related to the write-offs of certain regulatory assets associated with cancelled projects in 2020;

partially offset by

• The absence of a 2019 $12 million unfavorable adjustment to a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the merger transaction wherein we acquired all of the outstanding common units held by others of our former publicly traded master limited partnership.

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 control operating costs.

During 2021, we issued approximately $2.15 billion of new long-term debt primarily to fund current or near-term retirements.

In the first half of 2021, we acquired various oil and gas properties in the Wamsutter field in Wyoming, funding the $165 million paid with cash on hand.

In July 2021, we acquired Sequent, funding the final purchase price of $159 million paid with cash on hand (see Note 3 – Acquisitions of Notes to Consolidated Financial Statements).

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 2022 are currently expected to be in a range from $1.25 billion to $1.35 billion.

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.

We intend to fund substantially all of our planned 2022 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 as previously discussed in Recent Developments.

As of December 31, 2021, we have approximately $2.025 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 at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations.

In January 2022, we retired our $1.25 billion of 3.6 percent senior unsecured notes that were scheduled to mature in March 2022 with cash on hand.

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 intend to fund substantially all planned 2023 capital spending with cash available after paying dividends.

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.

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.

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.

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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

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Share repurchase program

As of December 31, 2021, we have approximately $21.650 billion of long-term debt due after one year.

See Note 13 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements 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 at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations.

At December 31, 2022, we have approximately $21.927 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.

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 December 31, 2021, we had a working capital deficit of $423 million, including cash and cash equivalents and long-term debt due within one year.

At December 31, 2022, we had a working capital deficit of $1.093 billion, including cash and cash equivalents and long-term debt due within one year.

Our available liquidity is as follows:

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(1) In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program.

We had no commercial paper outstanding as of December 31, 2021.

The highest amount outstanding under our commercial paper program and credit facility during 2021 was $15 million.

We had $350 million of commercial paper outstanding at December 31, 2022.

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

At December 31, 2022, we were in compliance with the financial covenants associated with our credit facility.

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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.

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.

No assurance can be given that

the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current criteria for investment-grade ratios.

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

Sources (Uses) of Cash

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

Proceeds from commercial paper - net Financing 345 — —

Contributions in aid of construction Investing 12 52 37

Proceeds from sale of partial interest in consolidated subsidiary (see Note 3)

Financing — — 1,334

Proceeds from dispositions of equity-method investments (see Note 9)

Investing 1 — 485

Uses of cash and cash equivalents:

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

Purchases of and contributions to equity-method investments (see Note 9)

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

Investing (933) (151) —

Dividends and distributions paid to noncontrolling interests Financing (204) (187) (185)

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

Purchases of and contributions to equity-method investments (see Note 8)

Investing (166) (115) (325)

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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 , Gain on disposition of equity-method investments , ( Gain) loss on deconsolidation of businesses , Impairment of goodwill , Impairment of equity-method investments , Impairment of certain assets, and Net unrealized (gain) loss from derivative instruments.

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.

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.

Our Net cash provided (used) by operating activities in 2020 decreased from 2019 primarily due to the net unfavorable changes in net operating working capital in 2020, including the payment of Transco’s rate refunds in 2020 and the decrease in the income tax refund that was received in 2020 compared to that received in 2019, partially offset by higher operating income (excluding noncash items as previously discussed) in 2020.

Environmental

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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 $31 million, all of which are included in Accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet at December 31, 2021.

We will seek recovery of the accrued costs related to remediation activities by our interstate gas pipelines totaling approximately $4 million through future natural gas transmission rates.

Current estimates of the most likely costs of such activities are approximately $40 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, 2022.

We will seek to recover approximately $4 million of accrued costs related to remediation activities by our interstate gas pipelines through future natural gas transmission rates.

The remainder of these costs will be funded from operations.

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however, due to regulatory uncertainty on final rule content and applicability timeframes, we are unable to reasonably estimate the cost these regulatory impacts at this time.

We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates for our interstate natural gas pipelines.

To date, we have been permitted recovery of these environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings.

Historically, with limited exceptions, we have been permitted recovery of these environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings.

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