10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

☑	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended	December 31, 2022
	OR
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from                      to

Commission file number 1-4174

The Williams Companies, Inc.

(Exact Name of Registrant as Specified in Its Charter)

Delaware		73-0569878
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)
One Williams Center
Tulsa	Oklahoma	74172
(Address of Principal Executive Offices)		(Zip Code)

800-945-5426 (800-WILLIAMS)

(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common Stock, $1.00 par value	WMB	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes ☑    No  ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ☐    No  ☑

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☑    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☑    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☑ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ☐    No  ☑

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as of the last business day of the registrant’s most recently completed second quarter was approximately $36,889,420,649.

The number of shares outstanding of the registrant’s common stock outstanding at February 17, 2023 was 1,218,562,959.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s Definitive Proxy Statement for the Registrant’s Annual Meeting of Stockholders to be held on April 25, 2023, are incorporated into Part III, as specifically set forth in Part III.

THE WILLIAMS COMPANIES, INC.

FORM 10-K

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business	5
	General	5
	Service Assets, Customers, and Contracts	6
	Business Segments	9
	Transmission & Gulf of Mexico	9
	Northeast G&P	13
	West	15
	Gas & NGL Marketing Services	17
	Other	18
	Regulatory Matters	18
	Environmental Matters	22
	Competition	22
	Human Capital Resources	23
	Website Access to Reports and Other Information	25
Item 1A.	Risk Factors	26
Item 1B.	Unresolved Staff Comments	40
Item 2.	Properties	40
Item 3.	Legal Proceedings	41
Item 4.	Mine Safety Disclosures	41
	Information About Our Executive Officers	42
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	44
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	46
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	69
Item 8.	Financial Statements and Supplementary Data	72
	Reports of Independent Registered Public Accounting Firms	72
	Consolidated Statement of Income	75
	Consolidated Statement of Comprehensive Income (Loss)	76
	Consolidated Balance Sheet	77
	Consolidated Statement of Changes in Equity	78
	Consolidated Statement of Cash Flows	79

1

	PART II (continued)
	Notes to Consolidated Financial Statements	80
	Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies	80
	Note 2 – Variable Interest Entities	92
	Note 3 – Acquisitions	94
	Note 4 – Related Party Transactions	98
	Note 5 – Revenue Recognition	99
	Note 6 – Provision (Benefit) for Income Taxes	102
	Note 7 – Employee Benefit Plans	104
	Note 8 – Investing Activities	109
	Note 9 – Property, Plant, and Equipment	111
	Note 10 – Intangible Assets	113
	Note 11 – Accrued and Other Current Liabilities	114
	Note 12 – Debt and Banking Arrangements	115
	Note 13 – Leases	119
	Note 14 – Equity-Based Compensation	119
	Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk	121
	Note 16 – Derivatives	126
	Note 17 – Contingent Liabilities and Commitments	127
	Note 18 – Segment Disclosures	131
	Note 19 – Subsequent Events	135
	Schedule II – Valuation and Qualifying Accounts	136
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	137
Item 9A.	Controls and Procedures	137
Item 9B.	Other Information	140
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	140
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	140
Item 11.	Executive Compensation	140
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	140
Item 13.	Certain Relationships and Related Transactions, and Director Independence	141
Item 14.	Principal Accountant Fees and Services	141
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	142
Item 16.	Form 10-K Summary	150

2

DEFINITIONS

The following is a listing of certain abbreviations, acronyms, and other industry terminology that may be used throughout this Annual Report.

Measurements:

Barrel or Bbl: One barrel of petroleum products that equals 42 U.S. gallons

Mbbls/d: One thousand barrels per day

Bcf : One billion cubic feet of natural gas

Bcf/d: One billion cubic feet of natural gas per day

MMcf/d: One million cubic feet per day

British Thermal Unit (Btu): A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit

MMbtu: One million British thermal units

Dekatherms (Dth): A unit of energy equal to one million British thermal units

Mdth/d: One thousand dekatherms per day

MMdth: One million dekatherms or approximately one trillion British thermal units

MMdth/d: One million dekatherms per day

Consolidated Entities: Entities in which we either own 100 percent ownership interest or for which we do not own 100 percent ownership interest but which we control and therefore consolidate, including the following:

Cardinal: Cardinal Gas Services, L.L.C.

Gulfstar One: Gulfstar One LLC

Northeast JV: Ohio Valley Midstream LLC

Northwest Pipeline: Northwest Pipeline LLC

Transco: Transcontinental Gas Pipe Line Company, LLC

Nonconsolidated Entities: Entities in which we do not own a 100 percent ownership interest and which, as of December 31, 2022, we account for as equity-method investments, including principally the following:

Aux Sable: Aux Sable Liquid Products LP

Blue Racer: Blue Racer Midstream LLC

Brazos Permian II: Brazos Permian II, LLC

Discovery: Discovery Producer Services LLC

Gulfstream: Gulfstream Natural Gas System, L.L.C.

Laurel Mountain: Laurel Mountain Midstream, LLC

OPPL: Overland Pass Pipeline Company LLC

RMM: Rocky Mountain Midstream Holdings LLC

Targa Train 7: Targa Train 7 LLC

Government and Regulatory:

EPA: Environmental Protection Agency

Exchange Act, the: Securities and Exchange Act of 1934, as amended

3

FERC: Federal Energy Regulatory Commission

IRS: Internal Revenue Service

SEC: Securities and Exchange Commission

Securities Act, the: Securities Act of 1933, as amended

Other:

EBITDA: Earnings before interest, taxes, depreciation, and amortization

Fractionation: The process by which a mixed stream of natural gas liquids is separated into constituent products, such as ethane, propane, and butane

GAAP: U.S. generally accepted accounting principles

LNG: Liquefied natural gas; natural gas which has been liquefied at cryogenic temperatures

MVC: Minimum volume commitments

NGLs: Natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are used as petrochemical feedstocks, heating fuels, and gasoline additives, among other applications

NGL margins: NGL revenues less Btu replacement cost, plant fuel, transportation, and fractionation

Appalachia Midstream Investments: Our equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region.

Sequent Acquisition: The July 1, 2021, acquisition of 100 percent of Sequent Energy Management, L.P. and Sequent Energy Canada, Corp.

Trace Acquisition: The April 29, 2022, acquisition of 100 percent of Gemini Arklatex, LLC.

NorTex Asset Purchase: The August 31, 2022, purchase of a group of assets in north Texas, primarily natural gas storage facilities and pipelines, from NorTex Midstream Holdings, LLC.

MountainWest Acquisition: The February 14, 2023, acquisition of 100 percent of MountainWest Pipelines Holding Company (MountainWest).

The statements in this Annual Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,” “in-service date,” or other similar expressions and other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that such expectations or assumptions will be achieved. Additional information regarding forward-looking statements and important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part I, Item 1A in this Annual Report.

4

PART I

Item 1. Business

In this report, Williams (which includes The Williams Companies, Inc. and, unless the context otherwise indicates, all of our subsidiaries) is at times referred to in the first person as “we,” “us,” or “our.” We also sometimes refer to Williams as the “Company.”

GENERAL

We are an energy company committed to being the leader in providing infrastructure that safely delivers natural gas products to reliably fuel the clean energy economy. We have operations in 14 supply areas that provide natural gas gathering, processing, and transmission services, NGLs fractionation, transportation, and storage services, and marketing services to more than 700 customers. We own an interest in and operate over 33,000 miles of pipelines in 25 states, 29 natural gas processing facilities, 7 NGL fractionation facilities, approximately 24 million barrels of NGL storage capacity, and 290.4 Bcf of natural gas storage capacity, and deliver natural gas that is used every day for clean-power generation, heating, and industrial use.

We were founded in 1908, originally incorporated under the laws of the state of Nevada in 1949 and reincorporated under the laws of the state of Delaware in 1987. Our common stock trades on the New York Stock Exchange under the symbol “WMB.” Our operations are located in the United States. Williams’ headquarters are located in Tulsa, Oklahoma, with other major offices in Houston, Texas and Pittsburgh, Pennsylvania. Our telephone number is 800-945-5426 (800-WILLIAMS).

5

Service Assets, Customers, and Contracts

Key variables for our businesses will continue to be:

•Obstacles to our expansion efforts, including delays or denials of necessary permits and opposition to hydrocarbon-based energy development;

•Producer drilling activities impacting natural gas supplies supporting our gathering and processing volumes;

•Retaining and attracting customers by continuing to provide reliable services;

•Revenue growth associated with additional infrastructure either completed or currently under construction;

•Prices impacting our commodity-based activities;

•Disciplined growth in our service areas.

Interstate Natural Gas Pipeline Assets

Our interstate natural gas pipelines, which are presented in our Transmission & Gulf of Mexico segment as described under the heading “Business Segments,” are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce are subject to regulation. The rates are established primarily through the FERC’s ratemaking process, but we also may negotiate rates with our customers pursuant to the terms of our tariffs and FERC policy.

Our interstate natural gas pipelines transport and store natural gas for a broad mix of customers, including local natural gas distribution companies, public utilities, municipalities, direct industrial users, electric power generators, and natural gas marketers and producers. Most of our interstate natural gas transmission businesses are fully contracted under long-term firm reservation contracts with high credit quality customers. These contracts have various expiration dates and account for the major portion of our regulated businesses. Additionally, we offer storage services and interruptible transportation services under shorter-term agreements. Transco’s and Northwest

6

Pipeline’s three largest customers in 2022 accounted for approximately 23 percent and 51 percent, respectively, of their total operating revenues.

Gathering, Processing, and Treating Assets

Our gathering, processing, and treating operations are presented within our Transmission & Gulf of Mexico, Northeast G&P, and West reporting segments as described under the heading “Business Segments.”

Our gathering systems receive natural gas from producers’ crude oil and natural gas wells and gather these volumes to gas processing, treating, or redelivery facilities. Typically, natural gas, in its raw form, is not acceptable for transportation in major interstate natural gas pipelines or for commercial use as a fuel. Our treating facilities remove water vapor, carbon dioxide, and other contaminants, and collect condensate. We are generally paid a fee based on the volume of natural gas gathered and/or treated, generally measured in the Btu heating value.

In addition, natural gas contains various amounts of NGLs, which generally have a higher value when separated from the natural gas stream. Our processing plants extract the NGLs, which include ethane, primarily used in the petrochemical industry; propane, used for heating, fuel, and also in the petrochemical industry; and, normal butane, isobutane, and natural gasoline, primarily used by the refining industry.

Our gas processing services generate revenues primarily from the following types of contracts:

•Fee-based: We are paid a fee based on the volume of natural gas processed, generally measured in the Btu heating value. A portion of our fee-based processing revenue includes a share of the margins on the NGLs produced. For the year ended December 31, 2022, approximately 90 percent of our NGL production volumes were under fee-based contracts.

•Noncash commodity-based: We also process gas under two types of commodity-based contracts, keep-whole and percent-of-liquids, where we receive consideration for our services in the form of NGLs. For a keep-whole arrangement we replace the Btu content of the retained NGLs with natural gas purchases, also known as shrink replacement gas. For a percent-of-liquids arrangement, we deliver an agreed-upon percentage of the extracted NGLs and retain the remainder. Retained NGLs are referred to as our equity NGL production. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. For the year ended December 31, 2022, approximately 10 percent of our NGL production volumes were under noncash commodity-based contracts.

Generally, our gathering and processing agreements are long-term agreements, with terms ranging from month-to-month to the life of the producing lease. Certain contracts include cost of service mechanisms that are designed to support a return on invested capital and allow our gathering rates to be adjusted, subject to specified caps in certain cases, to account for variability in volume, capital expenditures, commodity price fluctuations, compression, and other expenses. We also have certain gas gathering and processing agreements with MVC, whereby the customer is obligated to pay a contractually determined fee based on any shortfall between the actual gathered and processed volumes and the MVC for a stated period.

Demand for gas gathering and processing services is dependent on producers’ drilling activities, which is impacted by the strength of the economy, commodity prices, and the resulting demand for natural gas by manufacturing and industrial companies and consumers. Our gathering, processing, and treating businesses do not have direct exposure to crude oil prices. Our on-shore natural gas gathering and processing businesses are substantially focused on gas-directed drilling basins rather than crude oil, with a broad diversity of basins and customers served. Declines in crude oil drilling would be expected to result in less associated natural gas production, which could drive more demand for natural gas produced from gas-directed basins we serve.

During 2022, our facilities gathered and processed gas and crude oil for approximately 240 customers. Our top ten customers accounted for approximately 70 percent of our gathering and processing fee revenues and NGL margins from our noncash commodity-based agreements. We believe counterparty credit concerns in our gathering and processing businesses are significantly mitigated by the physical nature of our services, where we gather at the wellhead and are therefore critical to a producer’s ability to move product to market.

7

Gas and NGL Marketing

Our NGL and natural gas marketing services are presented primarily within our Gas & NGL Marketing Services segment. We market natural gas and NGL products to a wide range of users in the energy and petrochemical industries. In 2022, our three largest natural gas marketing customers accounted for approximately 12 percent of our gross natural gas marketing sales, and our three largest NGL marketing customers accounted for approximately 42 percent of our NGL marketing sales.

Our gas marketing business markets natural gas from the production at our upstream properties and provides asset management and the wholesale marketing, trading, storage, and transportation of natural gas for a diverse set of natural gas and electric utilities, municipalities, power generators, and producers, and moves gas to markets through transportation and storage agreements on strategically positioned assets. Our pipeline agreements connect with multiple pipelines that provide our customers with access to diverse sources of supply and various natural gas markets. The southeastern market served by our Gas & NGL Marketing Services segment is the fastest growing natural gas demand region in the United States and expands our natural gas marketing activities, as well as optimizes our pipeline and storage capabilities.

We purchase natural gas for storage when the current market price paid to buy and transport natural gas plus the cost to store and finance the natural gas is less than an estimated, forward market price that can be received in the future, resulting in positive net product sales. Commodity-based exchange-traded futures contracts and over-the-counter (OTC) contracts are used to sell natural gas at that future price to substantially protect the natural gas revenues that will ultimately be realized when the stored natural gas is sold. Additionally, we enter into transactions to secure transportation capacity between delivery points in order to serve our customers and various markets. Commodity-based exchange-traded futures contracts and OTC contracts are used to capture the price differential or spread between the locations served by the capacity in order to substantially protect the natural gas revenues that will ultimately be realized when the physical flow of natural gas between receipt and delivery points occurs.

Monthly demand charges incurred for the contracted storage and transportation capacity and payments associated with asset management agreements are substantially indirectly reimbursed by our customers. As we are acting as an agent, our natural gas marketing revenues are presented net of the related costs of those activities. In addition, all of our natural gas marketing derivative activities qualify as held for trading purposes, which requires net presentation in the Consolidated Statement of Income. Prior to the integration in 2022 of our historical gas marketing business with the acquired Sequent gas marketing business, natural gas marketing revenues and costs for our historical business were reported on a gross basis. Following the integration in 2022, the entire natural gas marketing portfolio is considered held for trading purposes, and the related revenues are therefore presented net of the related costs of those activities in 2022.

Our NGL marketing business transports and markets our equity NGLs from the production at our processing plants, NGLs from the production at our upstream properties, and also NGLs on behalf of third-party NGL producers, including some of our fee-based processing customers, as well as the NGL volumes owned by RMM and Discovery. The NGL marketing business bears the risk of price changes in these NGL volumes while they are being transported to final sales delivery points. In order to meet sales contract obligations, we may purchase products in the spot market for resale.

We are exposed to commodity price risk. To manage this volatility, we use various contracts in our marketing and trading activities that generally meet the definition of derivatives. We enter into commodity-related derivatives to hedge exposures to natural gas and NGLs and retain exposure to price changes that can, in a volatile energy market, be material and can adversely affect our results of operations.

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.

8

Crude Oil Transportation and Production Handling Assets

Our crude oil transportation operations, which are primarily presented in our Transmission & Gulf of Mexico segment as described under the heading “Business Segments,” earn revenues primarily from a combination of fixed-monthly fees, contractual fixed or variable fees applied to production volumes, and contributions in aid of construction (CIAC) arrangements. Generally, fixed-monthly fees associated with production handling and export revenues are recognized on a units-of-production basis utilizing either contractually determined maximum daily quantities or expected remaining production. CIAC arrangements are recognized based on a units of production basis, utilizing expected remaining production. Our crude oil transportation business is supported mostly by major oil producers with long-cycle perspectives.

BUSINESS SEGMENTS

Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented in Part I of this Annual Report within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, West, and Gas & NGL Marketing Services. All remaining business activities, including our upstream operations and corporate activities, are included in Other.

Our reportable segments are comprised of the following business activities:

•Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco, Northwest Pipeline, and MountainWest, and their related natural gas storage facilities, as well as natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One, a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery. Transmission & Gulf of Mexico also includes natural gas storage facilities and pipelines providing services in north Texas.

•Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 50 percent equity-method investment in Blue Racer, and Appalachia Midstream Investments.

•West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of east Texas and northwest Louisiana, and the Mid-Continent region which includes the Anadarko and Permian basins. This segment also includes our NGL storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, a 20 percent equity-method investment in Targa Train 7, and a 15 percent equity-method investment in Brazos Permian II.

•Gas & NGL Marketing Services includes our NGL and natural gas marketing and trading operations. This segment includes risk management and transactions related to the storage and transportation of natural gas and NGLs on strategically positioned assets.

Detailed discussion of each of our reportable segments follows. For a discussion of our ongoing expansion projects, see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Transmission & Gulf of Mexico

This segment includes the Transco interstate natural gas pipeline that extends from the Gulf of Mexico to the eastern seaboard, the Northwest Pipeline interstate natural gas pipeline, the MountainWest interstate natural gas pipeline, as well as natural gas gathering, processing and treating, crude oil production handling, and NGL fractionation assets within the onshore, offshore shelf, and deepwater areas in and around the Gulf Coast states of

9

Texas, Louisiana, Mississippi, and Alabama. This segment also includes various petrochemical and feedstock pipelines in the Gulf Coast region and natural gas pipelines and storage facilities located in north Texas.

Transco

Transco is an interstate natural gas transmission company that owns and operates a 9,700-mile natural gas pipeline system, which is regulated by the FERC, extending from Texas, Louisiana, Mississippi, and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania, and New Jersey to the New York City metropolitan area. The system serves customers in Texas and 12 southeast and Atlantic seaboard states, including major metropolitan areas in Georgia, North Carolina, Washington, D.C., Maryland, New York, New Jersey, and Pennsylvania.

At December 31, 2022, Transco’s system had a design capacity totaling approximately 18.6 MMdth/d. Transco’s system includes 59 compressor stations, four underground storage fields, and one LNG storage facility. Compression facilities at sea level-rated capacity total approximately 2.4 million horsepower.

Transco has natural gas storage capacity in four underground storage fields located on or near its pipeline system or market areas and operates two of these storage fields. Transco also has storage capacity in an LNG storage facility that it owns and operates. The total usable gas storage capacity available to Transco and its customers in such underground storage fields and LNG storage facility and through storage service contracts is approximately 188 Bcf of natural gas. At December 31, 2022, Transco’s customers had stored in its facilities approximately 127 Bcf of natural gas. Storage capacity permits our customers to inject gas into storage during the summer and off-peak periods for delivery during peak winter demand periods.

Northwest Pipeline

Northwest Pipeline is an interstate natural gas transmission company that owns and operates a 3,900-mile natural gas pipeline system, which is regulated by the FERC, extending from the San Juan basin in northwestern New Mexico and southwestern Colorado through Colorado, Utah, Wyoming, Idaho, Oregon, and Washington to a point on the Canadian border near Sumas, Washington. Northwest Pipeline provides services for markets in Washington, Oregon, Idaho, Wyoming, Nevada, Utah, Colorado, New Mexico, California, and Arizona, either directly or indirectly through interconnections with other pipelines.

At December 31, 2022, Northwest Pipeline’s system had a design capacity totaling approximately 3.8 MMdth/d. Northwest Pipeline’s system includes 42 transmission compressor stations having a combined sea level-rated capacity of approximately 476,000 horsepower.

Northwest Pipeline owns a one-third undivided interest in the Jackson Prairie underground storage facility in Washington. Northwest Pipeline also owns and operates a LNG storage facility in Washington. These storage facilities have an aggregate working natural gas storage capacity of 10.4 Bcf, which is substantially utilized for third-party natural gas. These natural gas storage facilities enable Northwest Pipeline to balance daily receipts and deliveries and provide storage services to customers.

North Texas Assets (NorTex)

On August 31, 2022, we purchased a group of assets in north Texas from NorTex Midstream Holdings, LLC. The NorTex assets include approximately 80 miles of natural gas transmission pipelines and 36 Bcf of natural gas storage in the Dallas-Fort Worth market. In addition to providing gas supply to power generation in north Texas, these assets also provide storage services for Permian gas directed toward growing Gulf Coast LNG demand.

MountainWest Acquisition

On February 14, 2023, we closed on the acquisition of 100 percent of MountainWest Pipelines Holding Company. MountainWest is an interstate natural gas pipeline company that owns and operates an approximately 2,000-mile natural gas pipeline system and provides transportation and underground natural gas storage services in Utah, Wyoming, and Colorado. At February 14, 2023, the MountainWest system had a design capacity totaling 8.0 MMdth/d. The system is located in the Rocky Mountains near six producing areas, including the Greater Green

10

River, Uinta, and Piceance basins. MountainWest also owns and operates 56 Bcf of natural gas storage capacity, including the Clay basin underground storage reservoir in Utah.

Gas Transportation, Processing, and Treating Assets

The following tables summarize the significant operated assets of this segment:

	Offshore Natural Gas Pipelines
	Location	Pipeline Miles	Inlet Capacity (Bcf/d)	Ownership Interest	Supply Basins
Consolidated:
Canyon Chief, including Blind Faith and Gulfstar extensions	Deepwater Gulf of Mexico	156	0.5	100%	Eastern Gulf of Mexico
Norphlet	Deepwater Gulf of Mexico	58	0.3	100%	Eastern Gulf of Mexico
Other Eastern Gulf	Offshore shelf and other	46	0.2	100%	Eastern Gulf of Mexico
Seahawk	Deepwater Gulf of Mexico	115	0.4	100%	Western Gulf of Mexico
Perdido Norte	Deepwater Gulf of Mexico	105	0.3	100%	Western Gulf of Mexico
Other Western Gulf	Offshore shelf and other	65	0.3	100%	Western Gulf of Mexico
Non-consolidated: (1)
Discovery	Central Gulf of Mexico	594	0.6	60%	Central Gulf of Mexico

	Natural Gas Processing Facilities
	Location	Inlet Capacity (Bcf/d)	NGL Production Capacity (Mbbls/d)	Ownership Interest	Supply Basins
Consolidated:
Markham	Markham, TX	0.5	45	100%	Western Gulf of Mexico
Mobile Bay	Coden, AL	0.7	35	100%	Eastern Gulf of Mexico
NorTex	Jack Co., TX	0.1	13	100%	Barnett Shale
Non-consolidated: (1)
Discovery	Larose, LA	0.6	32	60%	Central Gulf of Mexico

_____________

(1)Includes 100 percent of the statistics associated with operated equity-method investments.

Crude Oil Transportation and Production Handling Assets

In addition to our natural gas assets, we own and operate four deepwater crude oil pipelines and own production platforms serving the deepwater in the Gulf of Mexico. Our offshore floating production platforms provide centralized services to deepwater producers such as compression, separation, production handling, water removal, and pipeline landings.

11

The following tables summarize the significant crude oil transportation pipelines and production handling platforms of this segment:

	Crude Oil Pipelines
	Pipeline Miles	Capacity (Mbbls/d)	Ownership Interest	Supply Basins
Consolidated:
Mountaineer, including Blind Faith and Gulfstar extensions	155	150	100%	Eastern Gulf of Mexico
BANJO	57	90	100%	Western Gulf of Mexico
Alpine	96	85	100%	Western Gulf of Mexico
Perdido Norte	74	150	100%	Western Gulf of Mexico

	Production Handling Platforms
	Gas Inlet Capacity (MMcf/d)	Crude/NGL Handling Capacity (Mbbls/d)	Ownership Interest	Supply Basins
Consolidated:
Devils Tower	110	60	100%	Eastern Gulf of Mexico
Gulfstar I FPS (1)	172	80	51%	Eastern Gulf of Mexico
Non-consolidated: (2)
Discovery	75	10	60%	Central Gulf of Mexico

__________

(1)Statistics reflect 100 percent of the assets from our 51 percent interest in Gulfstar One.

(2)Includes 100 percent of the statistics associated with operated equity-method investments.

Transmission & Gulf of Mexico Operating Statistics

	2022	2021	2020
	(Annual Average Amounts)
Consolidated:
Interstate natural gas pipeline throughput (MMdth/d) (2)	16.9	16.2	15.1
Gathering volumes (Bcf/d)	0.29	0.28	0.25
Plant inlet natural gas volumes (Bcf/d)	0.47	0.45	0.48
NGL production (Mbbls/d)	28	29	29
NGL equity sales (Mbbls/d)	6	6	5
Crude oil transportation (Mbbls/d)	119	134	121
Non-consolidated: (1)
Interstate natural gas pipeline throughput (MMdth/d) (2)	1.3	1.2	1.2
Gathering volumes (Bcf/d)	0.40	0.35	0.30
Plant inlet natural gas volumes (Bcf/d)	0.40	0.35	0.30
NGL production (Mbbls/d)	28	27	21
NGL equity sales (Mbbls/d)	8	8	6

_____________

(1)Includes 100 percent of the volumes associated with operated equity-method investments.

(2)Tbtu converted to MMdth at one trillion British thermal units = one million dekatherms.

12

Certain Equity-Method Investments

Gulfstream

Gulfstream is a 745-mile interstate natural gas pipeline system extending from the Mobile Bay area in Alabama to markets in Florida, which has a capacity to transport 1.4 Bcf/d. We own a 50 percent equity-method investment in Gulfstream. We share operating responsibilities for Gulfstream with the other 50 percent owner.

Discovery

We own a 60 percent interest in and operate the facilities of Discovery. Discovery’s assets include a 600 MMcf/d cryogenic natural gas processing plant near Larose, Louisiana, a 32 Mbbls/d NGL fractionator plant near Paradis, Louisiana, and a 594-mile offshore natural gas gathering and transportation system in the Gulf of Mexico. Discovery’s mainline has a gathering inlet capacity of 600 MMcf/d. Discovery’s assets also include a crude oil production handling platform with capacity of 10 Mbbls/d and gas handling and separation capacity of 75 MMcf/d.

Northeast G&P

This segment includes our natural gas gathering, compression, processing, and NGL fractionation businesses in the Marcellus and Utica Shale regions in Pennsylvania, West Virginia, New York, and Ohio.

The following tables summarize the significant operated assets of this segment and non-operated Blue Racer:

	Natural Gas Gathering Assets
	Location	Pipeline Miles	Inlet Capacity (Bcf/d)	Ownership Interest	Supply Basins
Consolidated:
Ohio Valley Midstream (1)	Ohio, West Virginia, & Pennsylvania	216	0.8	65%	Appalachian
Utica East Ohio Midstream (1) (2)	Ohio	53	0.6	65%	Appalachian
Susquehanna Supply Hub	Pennsylvania & New York	479	4.3	100%	Appalachian
Cardinal (1)	Ohio	395	0.7	66%	Appalachian
Flint	Ohio	100	0.5	100%	Appalachian
Non-consolidated: (3)
Bradford Supply Hub	Pennsylvania	750	4.0	66%	Appalachian
Marcellus South	Pennsylvania & West Virginia	290	1.3	68%	Appalachian
Laurel Mountain	Pennsylvania	1,145	0.9	69%	Appalachian
Blue Racer	Ohio & West Virginia	741	1.5	50%	Appalachian

	Natural Gas Processing Facilities
	Location	Inlet Capacity (Bcf/d)	NGL Production Capacity (Mbbls/d)	Ownership Interest	Supply Basins
Consolidated: (1)
Fort Beeler	Marshall Co., WV	0.5	62	65%	Appalachian
Oak Grove	Marshall Co., WV	0.6	75	65%	Appalachian
Kensington	Columbiana Co., OH	0.6	68	65%	Appalachian
Leesville	Carroll Co., OH	0.2	18	65%	Appalachian
Non-consolidated: (3) (4)
Berne	Monroe Co., OH	0.4	60	50%	Appalachian
Natrium	Marshall Co., WV	0.8	120	50%	Appalachian

_____________

(1)Statistics reflect 100 percent of the assets from our 65 percent ownership in our Northeast JV and 66 percent ownership of Cardinal gathering system.

13

(2)Utica East Ohio Midstream inlet capacity consists of 1.3 Bcf/d of a high-pressure gathering pipeline that delivers Cardinal gathering volumes to Utica East Ohio Midstream processing facilities. The listed inlet capacity of 0.6 Bcf/d is incremental capacity to the Cardinal gathering capacity of 0.7 Bcf/d.

(3)Includes 100 percent of the statistics associated with operated equity-method investments and non-operated Blue Racer.

(4)Natural gas processing facilities owned by non-operated Blue Racer.

Other NGL Operations

We own and operate a 43 Mbbls/d NGL fractionation facility at Moundsville, West Virginia, de-ethanization and condensate facilities at our Oak Grove processing plant, a condensate stabilization facility near our Moundsville fractionator, an ethane pipeline, and an NGL pipeline. Our Oak Grove de-ethanizer is capable of handling up to approximately 80 Mbbls/d of mixed NGLs to extract up to approximately 40 Mbbls/d of ethane. Our condensate stabilizers are capable of handling approximately 17 Mbbls/d of field condensate. We also own and operate 44 Mbbls/d of condensate stabilization capacity, a 135 Mbbls/d NGL fractionation facility, approximately 970,000 barrels of NGL storage capacity, and other ancillary assets, including loading and terminal facilities in Ohio.

NGLs are extracted from the natural gas stream in our Oak Grove and Fort Beeler cryogenic processing plants. Ethane produced at our de-ethanizer is transported to markets via our 50-mile ethane pipeline from Oak Grove to Houston, Pennsylvania. The remaining mixed NGL stream from the de-ethanizer is then transported via our 50-mile NGL pipeline and fractionated at either our Moundsville or Harrison County, Ohio, fractionation facility. The resulting products are then transported on truck, rail, or pipeline. Ohio Valley Midstream provides residue natural gas take away options for our customers with interconnections to three interstate transmission pipelines.

Northeast G&P Operating Statistics

	2022	2021	2020
	(Annual Average Amounts)
Consolidated:
Gathering volumes (Bcf/d)	4.19	4.24	4.31
Plant inlet natural gas volumes (Bcf/d)	1.65	1.57	1.32
NGL production (Mbbls/d)	120	115	103
NGL equity sales (Mbbls/d)	1	1	2
Non-consolidated: (1)
Gathering volumes (Bcf/d)	6.61	6.79	6.16
Plant inlet natural gas volumes (Bcf/d)	0.71	0.82	0.95
NGL production (Mbbls/d)	51	56	65
NGL equity sales (Mbbls/d)	3	6	6

__________

(1)    Includes 100 percent of the volumes associated with operated equity-method investments, including the Laurel Mountain Midstream partnership; and the Bradford Supply Hub and the Marcellus South Supply Hub within Appalachia Midstream Investments. Periods after November 18, 2020, have been updated to include non-operated Blue Racer volumes. Further, the amounts for Blue Racer presented for 2020 are averages for the 44 days over which we included Blue Racer, not averages over the entire year.

Certain Equity-Method Investments

Appalachia Midstream Investments    

Through our Appalachia Midstream Investments, we operate 100 percent of and own an approximate average 66 percent interest in the Bradford Supply Hub gathering system and own an approximate average 68 percent interest in the Marcellus South gathering system, together which consist of approximately 1,040 miles of gathering

14

pipeline in the Marcellus Shale region with the capacity to gather 5,330 MMcf/d of natural gas. The majority of our volumes in the region are gathered from northern Pennsylvania, southwestern Pennsylvania, and the northwestern panhandle of West Virginia in core areas of the Marcellus Shale. We operate the assets under long-term, 100 percent fixed-fee gathering agreements that include significant acreage dedications and, in the Bradford Supply Hub, a cost of service mechanism. Additionally, some Marcellus South agreements have MVCs.

Laurel Mountain

We own a 69 percent interest in a joint venture, Laurel Mountain, that includes a 1,145-mile gathering system that we operate in western Pennsylvania with the capacity to gather 0.9 Bcf/d of natural gas. Laurel Mountain has a long-term, dedicated, volumetric-based fee agreement, with exposure to natural gas prices, to gather the anchor customer’s production in the western Pennsylvania area of the Marcellus Shale. Additionally, certain Laurel Mountain agreements have MVCs.

Blue Racer

We own a 50 percent interest in Blue Racer which is operated by Blue Racer Midstream Holdings, LLC (BRMH). BRMH (previously named Caiman Energy II, LLC), a former equity-method investment, is a consolidated entity following our acquisition of a controlling interest in November 2020 and the remaining interest in September 2021. BRMH’s primary asset is a 50 percent interest in Blue Racer, accounted for as an equity-method investment. Blue Racer is a joint venture to own, operate, develop, and acquire midstream assets in the Utica Shale and certain adjacent areas in the Marcellus Shale. Blue Racer’s assets include 741 miles of gathering pipelines, and the Natrium complex in Marshall County, West Virginia, with a cryogenic processing capacity of 800 MMcf/d and fractionation capacity of approximately 134 Mbbls/d. Blue Racer also owns the Berne complex in Monroe County, Ohio, with a cryogenic processing capacity of 400 MMcf/d, and NGL and condensate pipelines connecting Natrium to Berne. Blue Racer provides gathering, processing, and marketing services primarily under percent-of-liquids and fixed-fee agreements.

West

Gas Gathering, Processing, and Treating Assets

The following tables summarize the significant operated assets of this segment:

	Natural Gas Gathering Assets
	Location	Pipeline Miles	Inlet Capacity (Bcf/d)	Ownership Interest	Supply Basins/Shale Formations
Consolidated:
Wamsutter	Wyoming	2,265	0.7	100%	Wamsutter
Southwest Wyoming	Wyoming	1,614	0.5	100%	Southwest Wyoming
Piceance	Colorado	352	1.8	100%	Piceance
Barnett Shale	Texas	839	0.5	100%	Barnett Shale
Eagle Ford Shale	Texas	1,251	0.5	100%	Eagle Ford Shale
Haynesville Shale (1)	Louisiana & Texas	929	4.7	100%	Haynesville Shale, Bossier Shale
Permian	Texas	112	0.1	100%	Permian
Mid-Continent	Oklahoma & Texas	1,752	0.2	100%	Miss-Lime, Granite Wash, Colony Wash
Non-consolidated: (2)
Rocky Mountain Midstream	Colorado	208	0.6	50%	Denver-Julesburg

15

	Natural Gas Processing Facilities
	Location	Inlet Capacity (Bcf/d)	NGL Production Capacity (Mbbls/d)	Ownership Interest	Supply Basins
Consolidated:
Echo Springs	Echo Springs, WY	0.6	48	100%	Wamsutter
Opal	Opal, WY	1.1	47	100%	Southwest Wyoming
Willow Creek	Rio Blanco Co., CO	0.5	30	100%	Piceance
Parachute	Garfield Co., CO	1.0	5	100%	Piceance
Non-consolidated: (2)
Fort Lupton	Weld Co., CO	0.3	50	50%	Denver-Julesburg
Keenesburg I	Weld Co., CO	0.2	40	50%	Denver-Julesburg

_______________

(1)Includes statistics for assets acquired in the Trace Acquisition.

(2)Includes 100 percent of the statistics associated with operated equity-method investments.

Other NGL Operations

We own interests in and/or operate NGL fractionation and storage assets in central Kansas near Conway. These assets include a 50 percent interest in an NGL fractionation facility with capacity of slightly more than 100 Mbbls/d and we own approximately 23 million barrels of NGL storage capacity. We also own a 189-mile NGL pipeline from our fractionator near Conway, Kansas, to an interconnection with a third-party NGL pipeline system in Oklahoma.

West Operating Statistics

	2022	2021	2020
	(Annual Average Amounts)
Consolidated:
Gathering volumes (Bcf/d) (1)	5.19	3.25	3.33
Plant inlet natural gas volumes (Bcf/d)	1.15	1.23	1.25
NGL production (Mbbls/d)	43	41	49
NGL equity sales (Mbbls/d)	14	16	22
Non-Consolidated: (2)
Gathering volumes (Bcf/d)	0.29	0.29	0.25
Plant inlet natural gas volumes (Bcf/d)	0.28	0.28	0.25
NGL production (Mbbls/d)	33	29	23

________________

(1)    Includes volumes for gathering assets acquired in the Trace Acquisition after the purchase on April 29, 2022. Further, the amounts for the acquired assets presented for 2022 are averaged over the period owned, not over the entire year.

(2)    Includes 100 percent of the volumes associated with operated equity-method investments.

16

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. The purpose of this acquisition was to expand our footprint into the east Texas area of the Haynesville Shale region, increasing in-basin scale.

Certain Equity-Method Investments

Overland Pass Pipeline

We operate and own a 50 percent interest in OPPL. OPPL is capable of transporting 255 Mbbls/d of NGLs and includes approximately 1,035 miles of NGL pipeline extending from Opal, Wyoming, to the Mid-Continent NGL market center near Conway, Kansas, along with extensions into the Piceance and Denver-Julesberg basins in Colorado and the Bakken Shale in the Williston basin in North Dakota. Our equity NGL volumes from our Wyoming plants and our Willow Creek facility in Colorado are dedicated for transport on OPPL under a long-term transportation agreement. NGL volumes from our RMM equity-method investment are also transported on OPPL.

Rocky Mountain Midstream

We operate and own a 50 percent interest in RMM. RMM includes a natural gas gathering pipeline, an approximate 100-mile crude oil transportation pipeline, and natural gas processing assets in Colorado’s Denver-Julesburg basin. It also includes crude oil storage and compression assets.

Brazos Permian II

We own a 15 percent interest in Brazos Permian II, a privately held Permian basin midstream company.

Targa Train 7

We own a 20 percent interest in Targa Train 7, a Mt. Belvieu, Texas, fractionation train.

Gas & NGL Marketing Services

Our natural gas marketing business provides asset management and the wholesale marketing, trading, storage, and transportation of natural gas for a diverse set of natural gas and electric utilities, municipalities, power generators, and producers and markets natural gas from the production at our upstream properties. The Sequent Acquisition in July 2021 significantly increased the scope of our natural gas marketing operations. Our NGL marketing business transports and markets our equity NGLs from the production at our processing plants, NGLs from the production at our upstream properties, and also NGLs on behalf of third-party NGL producers, including some of our fee-based processing customers. See the Gas and NGL Marketing section of Service Assets, Customers, and Contracts in Item 1. Business for additional information related to this business segment.

Gas & NGL Marketing Services Operating Statistics

	2022	2021	2020
	(Annual Average Amounts)
Sales Volumes:
Natural Gas (Bcf/d) (1) (2)	7.20	7.70	0.62
NGLs (Mbbls/d) (2)	250	227	220

________________

(1)    Includes 100% of the volumes associated with the Sequent Acquisition after the purchase on July 1, 2021. Further, the amounts for the acquired assets presented for 2021 are averaged over the period owned, not over the entire year.

(2)    2021 amounts have been updated to reflect revised natural gas and NGL volumes. 2020 amounts have been updated to reflect revised NGL volumes.

17

Other

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

Upstream Ventures

We acquired certain crude oil and natural gas properties in the Wamsutter basin in February 2021. These properties were conveyed to a venture in the third quarter of 2021 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 third party will receive an additional 25 percent of any new wells and 50 percent of the remaining undeveloped acreage 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.

Certain natural gas properties in Louisiana were transferred to us in November 2020 as part of a bankruptcy resolution with one of our customers. In the third quarter of 2021, we sold 50 percent of the 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 operates the upstream position and develops the undeveloped acreage. When a certain drilling hurdle is met, the third party’s interest in new wells increases to 75 percent. The third party met this drilling hurdle in early 2023. We retain ownership in the undeveloped acreage until a separate acreage earning hurdle is 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.

Operating Statistics

	2022	2021
	(Annual Average Amounts)
Net Product Sales Volumes:
Natural Gas (Bcf/d)	0.22	0.13
NGLs (Mbbls/d)	7	6
Crude Oil (Mbbls/d)	2	2

New Energy Ventures

Our Other segment also includes investments in new energy ventures related to hydrogen, solar, renewable natural gas, and NextGen Gas. NextGen Gas is natural gas that has been independently certified as low emissions gas across all segments of the value chain.

REGULATORY MATTERS

FERC

Our gas pipeline interstate transmission and storage activities are subject to FERC regulation under the Natural Gas Act of 1938 (NGA) and under the Natural Gas Policy Act of 1978, and, as such, our rates and charges for the transportation of natural gas in interstate commerce, accounting, and the extension, enlargement, or abandonment of our jurisdictional facilities, among other things, are subject to regulation. Each of our gas pipeline companies holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities, and properties for which certificates are required under the NGA. FERC Standards of Conduct govern how our interstate pipelines communicate and conduct transmission transactions with an affiliate that engages in marketing functions. Among other things, the Standards of Conduct require that interstate gas pipelines treat all transmission customers, affiliated and non-affiliated, on a not unduly discriminatory basis.

18

FERC regulation requires all terms and conditions of service, including the rates charged, to be filed with and approved by the FERC before any changes can go into effect. Our interstate gas pipeline companies establish rates through the FERC’s ratemaking process. In addition, our interstate gas pipelines may enter into negotiated rate agreements where cost-based recourse rates are made available. Key determinants in the FERC ratemaking process include:

•Costs of providing service, including depreciation expense;

•Allowed rate of return, including the equity component of the capital structure and related income taxes;

•Contract and volume throughput assumptions.

The allowed rate of return is determined in each rate case. Rate design and the allocation of costs between the reservation and commodity rates also impact profitability. As a result of these proceedings, certain revenues previously collected may be subject to refund.

We also own interests in and operate natural gas liquids pipelines that are regulated by various federal and state governmental agencies. Services provided on our interstate natural gas liquids pipelines are subject to regulation under the Interstate Commerce Act by the FERC, which has authority over the terms and conditions of service; rates, including depreciation and amortization policies; and initiation of service. Our intrastate natural gas liquids pipelines providing common carrier service are subject to regulation by various state regulatory agencies.

Updated Certificate Policy Statement and Interim Greenhouse Gas (GHG) Policy Statement

On February 18, 2022, the FERC issued two policy statements providing guidance for its pending and future consideration of interstate natural gas pipeline projects. The first policy statement is an Updated Certificate Policy Statement, which provides an analytical framework for how the FERC will consider whether a project is in the public convenience and necessity and explains that the FERC will consider all impacts of a proposed project, including economic and environmental impacts, together. The second policy statement is an Interim GHG Policy Statement, which sets forth how the FERC will assess the impacts of natural gas infrastructure projects on climate change in its reviews under the National Environmental Policy Act and the NGA. The FERC sought comment on all aspects of the policy statements, including the approach to assessing the significance of the proposed project’s contribution to climate change. On March 24, 2022, the FERC issued an order converting the Updated Certificate Policy Statement and the Interim GHG Policy Statement into draft policy statements and announcing that it will not apply either policy statement to pending applications or applications filed before the FERC issues any final guidance on the policy statements. The FERC has not yet issued final guidance on the policy statements.

Pipeline Safety

Our gas pipelines are subject to the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Improvement Act of 2002, the Pipeline Safety, Regulatory Certainty, and Jobs Creation Act of 2011, and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 and 2020, which regulate safety requirements in the design, construction, operation, and maintenance of interstate natural gas transmission facilities. The United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) administers federal pipeline safety laws.

Federal pipeline safety laws authorize PHMSA to establish minimum safety standards for pipeline facilities and persons engaged in the transportation of gas or hazardous liquids by pipeline. These safety standards apply to the design, construction, testing, operation, and maintenance of gas and hazardous liquids pipeline facilities affecting interstate or foreign commerce. PHMSA has also established reporting requirements for operators of gas and hazardous liquid pipeline facilities, as well as provisions for establishing the qualification of pipeline personnel and requirements for managing the integrity of gas transmission and distribution lines and certain hazardous liquid pipelines. To ensure compliance with these provisions, PHMSA performs pipeline safety inspections and has the authority to initiate enforcement actions.

19

In October 2019, PHMSA published the first of three rules that would be a part of the Mega Rule. The Mega Rule was more than 10 years in the making and since October 2019, PHMSA has also published Rules 2 and 3 as a part of the Mega Rule implementation. At the end of 2021, PHMSA published Rule 3 of the Mega Rule with an implementation date in May 2022. Rule 3 was also called The Gas Gathering Rule and expanded Federal Pipeline Safety oversight to more than 400,000 miles of pipeline across all operators, including approximately 5,400 miles and 4,500 miles of our regulated and unregulated pipelines, respectively. The rule established Federal pipeline safety oversight on previously unregulated gas gathering pipelines. The rule limits the use of “incidental gathering pipelines” to 10 miles in length or less. The rule also creates a new category of regulated gas gathering pipelines that are located in rural locations and will be subject to certain reporting and safety standards. New regulations in Rule 3 include requirements for public awareness, emergency response, damage prevention, incident notification, and annual reporting. As a result of the rule, we revised numerous procedures and are now reporting based on the expanded scope as required by regulation.

In August 2022, PHMSA published Rule 2, which is the last in the three part Mega Rule set of regulations. Certain portions of Rule 2 go into effect in May 2023 with the remaining portions taking effect in February 2024. Rule 2 contains new corrosion control requirements, new requirements for repair criteria outside of high consequence areas (HCAs), inspections to be performed after extreme weather events or natural disasters, management of change, and other integrity management related rule changes. We are evaluating procedures that will need to be updated to maintain compliance and are also analyzing anticipated cost impacts.

PHMSA’s new rule, Requirement of Valve Installation and Minimum Rupture Detection Standards, went into effect in October 2022. The rupture monitoring and emergency response standards are applicable to existing pipelines, but the installation of rupture mitigation valves (RMVs) is not retroactive and only applies to new pipelines and significant pipeline replacements. This new rule establishes criteria for how operators must monitor and respond to potential ruptures on their system. It also outlines requirements for the installation of RMVs or Alternative Equivalent Technology to allow for quicker isolation after an incident has occurred. In response to the new regulation, Williams has updated all applicable procedures and is developing implementation plans as a result of the rulemaking.

Pipeline Integrity Regulations

We have an enterprise-wide Gas Integrity Management Plan that meets the PHMSA final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rules require gas pipeline operators to develop an integrity management program for pipelines that could affect HCAs in the event of pipeline failure. The integrity management program includes a baseline assessment plan along with periodic reassessments to be completed within required time frames. In meeting the integrity regulations, we have identified HCAs and developed baseline assessment plans. Ongoing periodic reassessments and initial assessments of any new HCAs have been completed. Also, in response to the portion of the Mega Rule implemented in 2021, we have identified Moderate Consequence Areas, and Class 3 and 4 pipeline locations required by the rule and integrated those segments into our integrity program, and have begun scheduling required assessments and reassessments as needed to meet the regulatory timelines. We estimate that the cost to be incurred in 2023 associated with this program to be approximately $126 million. Management considers costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through Northwest Pipeline’s and Transco’s rates.

We have an enterprise-wide Liquid Integrity Management Plan that we believe meets the PHMSA final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires liquid pipeline operators to develop an integrity management program for liquid transmission pipelines that could affect HCAs in the event of pipeline failure. The integrity management program includes a baseline assessment plan along with periodic reassessments expected to be completed within required time frames. In meeting the integrity regulations, we utilized government defined HCAs and developed baseline assessment plans. We completed assessments within the required time frames. We estimate that the cost to be incurred in 2023 associated with this program will be approximately $10 million. Ongoing periodic reassessments and initial assessments of any new HCAs are expected to be completed within the time frames required by the rule. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business.

20

Cybersecurity Matters

The Transportation Security Administration (TSA) issued Security Directive Pipeline-2021-01B (Security Directive 1B) on May 29, 2022, which requires that owners/operators of critical pipelines (1) report cybersecurity incidents to the Cybersecurity and Infrastructure Agency (CISA) within 24 hours; (2) appoint a cybersecurity coordinator to coordinate with TSA and CISA; and (3) conduct a self-assessment of cybersecurity practices, identify any gaps, and develop a plan and timeline for remediation. On July 27, 2022, the TSA issued Security Directive Pipeline-2021-02C (Security Directive 2C), which requires owners/operators of critical pipelines to (1) establish and implement a TSA-approved Cybersecurity Implementation Plan that describes the specific cybersecurity measures employed and the schedule for achieving the cybersecurity outcomes described in Security Directive 2C; (2) develop and maintain a Cybersecurity Incident Response Plan to reduce the risk of operational disruption or other significant impacts from a cybersecurity incident; and (3) establish a Cybersecurity Assessment Program and submit an annual plan describing how the effectiveness of cybersecurity measures will be assessed. We have established and received TSA approval for our Cybersecurity Implementation Plan and are compliant with the remaining requirements established in Security Directives 1B and 2C. New regulations or security directives issued by TSA may impose additional requirements applicable to our cybersecurity program, which could cause us to incur increased capital and operating costs and operational delays.

See Part I, Item 1A. “Risk Factors” — “A breach of our information technology infrastructure, including a breach caused by a cybersecurity attack on us or third parties with whom we are interconnected, may interfere with the safe operation of our assets, result in the disclosure of personal or proprietary information, and harm our reputation.”

State Gathering Regulations

Our onshore midstream gathering operations are subject to laws and regulations in the various states in which we operate. For example, the Texas Railroad Commission has the authority to regulate the terms of service for our intrastate natural gas gathering business in Texas. Although the applicable state regulations vary widely, they generally require that pipeline rates and practices be reasonable and nondiscriminatory, and may include provisions covering marketing, pricing, pollution, environment, and human health and safety. Some states, such as New York and Ohio, have specific regulations pertaining to the design, construction, and operations of gathering lines within such state.

Intrastate Liquids Pipelines in the Gulf Coast

Our intrastate liquids pipelines in the Gulf Coast are regulated by the Louisiana Department of Natural Resources, the Texas Railroad Commission, and various other state and federal agencies. These pipelines are also subject to the liquid pipeline safety and integrity regulations discussed above since both Louisiana and Texas have adopted the integrity management regulations defined in PHMSA.

OCSLA

Our offshore gas and liquids pipelines located on the outer continental shelf are subject to the Outer Continental Shelf Lands Act, which provides in part that outer continental shelf pipelines “must provide open and nondiscriminatory access to both owner and non-owner shippers.”

See Part I, Item 1A. “Risk Factors” — “The operation of our businesses might be adversely affected by regulatory proceedings, changes in government regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers,” and “The natural gas sales, transportation, and storage operations of our gas pipelines are subject to regulation by the FERC, which could have an adverse impact on their ability to establish transportation and storage rates that would allow them to recover the full cost of operating their respective pipelines and storage assets, including a reasonable rate of return.”

21

ENVIRONMENTAL MATTERS

Our operations are subject to federal environmental laws and regulations as well as the state, local, and tribal laws and regulations adopted by the jurisdictions in which we operate. We could incur liability to governments or third parties for any unlawful discharge of pollutants into the air, soil, or water, as well as liability for cleanup costs. Materials could be released into the environment in several ways including, but not limited to:

•Leakage from gathering systems, underground gas storage caverns, pipelines, processing or treating facilities, transportation facilities, and storage tanks;

•Damage to facilities resulting from accidents during normal operations;

•Damages to onshore and offshore equipment and facilities resulting from storm events or natural disasters;

•Blowouts, cratering, and explosions.

In addition, we may be liable for environmental damage caused by former owners or operators of our properties.

We believe compliance with current environmental laws and regulations will not have a material adverse effect on our capital expenditures, earnings, or current competitive position. However, environmental laws and regulations could affect our business in various ways from time to time, including incurring capital and maintenance expenditures, fines and penalties, and creating the need to seek relief from the FERC for rate increases to recover the costs of certain capital expenditures and operation and maintenance expenses.

For additional information regarding the potential impact of federal, state, tribal, or local regulatory measures on our business and specific environmental issues, please refer to Part 1, Item 1A. “Risk Factors” — “Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities, and expenditures that could exceed our expectations,” and Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Environmental” and “Environmental Matters” in Part II, Item 8. Financial Statements and Supplementary Data — Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements.

COMPETITION

Gathering and Processing

Competition for natural gas gathering, processing, treating, transportation, and storage, as well as NGLs transportation, fractionation, and storage continues to increase as production from shales and other resource areas continues to grow. Our midstream services compete with similar facilities that are in the same proximity as our assets.

We face competition from companies of varying size and financial capabilities, including major and independent natural gas midstream providers, private equity firms, and major integrated oil and natural gas companies that gather, transport, process, fractionate, store, and market natural gas and NGLs, as well as some larger exploration and production companies that are choosing to develop midstream services to handle their own natural gas.

Our gathering and processing agreements are generally long-term agreements that may include acreage dedication. Competition for natural gas volumes is primarily based on reputation, commercial terms (products retained or fees charged), array of services provided, efficiency and reliability of services, location of gathering facilities, available capacity, downstream interconnects, and latent capacity. We believe our significant presence in traditional prolific supply basins, our solid positions in growing shale plays, our expertise and reputation as a reliable operator, and our ability to offer integrated packages of services position us well against our competition.

22

Regulated Interstate Natural Gas Transportation and Storage

The market for supplying natural gas is highly competitive and new pipelines, storage facilities, and other related services are expanding to service the growing demand for natural gas. Additionally, pipeline capacity in many growing natural gas supply basins is constrained causing competition to increase among pipeline companies as they strive to connect those basins to major natural gas demand centers.

In our business, we predominately compete with major intrastate and interstate natural gas pipelines. In the last few years, local distribution companies have also started entering into the long-haul transportation business through joint venture pipelines. The principle elements of competition in the interstate natural gas pipeline business are based on capacity available, rates, reliability, quality of customer service, diversity of supply, and proximity to customers and market hubs.

We face competition in a number of our key markets and we compete with other interstate and intrastate pipelines for deliveries to customers who can take deliveries at multiple points. Natural gas delivered on our system competes with alternative energy sources used to generate electricity such as hydroelectric power, coal, fuel oil, and nuclear. Future demand for natural gas within the power sector could be increased by regulations limiting or discouraging coal use or could be adversely affected by laws mandating or encouraging renewable power sources.

Significant entrance barriers to build new pipelines exist, including federal and growing state regulations and public opposition against new pipeline builds, and these factors will continue to impact potential competition for the foreseeable future. However, we believe our past success in working with regulators and the public, the position of our existing infrastructure, established strategic long-term contracts, and the fact that our pipelines have numerous receipt and delivery points along our systems provide us a competitive advantage, especially along the eastern seaboard and northwestern United States.

Energy Management and Marketing Services

Our Gas & NGL Marketing Services segment competes with national and regional full-service energy providers, producers, and pipelines marketing affiliates or other marketing companies that aggregate commodities with transportation and storage capacity.

For additional information regarding competition for our services or otherwise affecting our business, please refer to Part 1, Item 1A. “Risk Factors” - “The financial condition of our natural gas transportation and midstream businesses is dependent on the continued availability of natural gas supplies in the supply basins that we access and demand for those supplies in the markets we serve,” “Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results,” and “We may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, or at all, which could affect our financial condition, the amount of cash available to pay dividends, and our ability to grow.”

HUMAN CAPITAL RESOURCES

We are committed to maintaining a work environment that enables us to attract, develop, and retain a highly skilled and diverse group of talented employees who help promote long-term value creation.

Employees

As of February 1, 2023, we had 5,043 full-time employees located throughout the United States. Of this total, approximately 22 percent are women and 17 percent are ethnically diverse. During 2022, our voluntary turnover rate was 7.7 percent.

We encourage you to review our 2021 Sustainability Report available on our website for more information about our human capital programs and initiatives. Nothing on our website shall be deemed incorporated by reference into this Annual Report on Form 10-K.

23

Workforce Safety

We continue to advance our safety-first culture by developing and empowering our employees to operate our assets in a safe, reliable, and customer-focused way. We strive to continuously improve safety and work towards zero safety incidents. When a safety hazard is recognized, every employee is empowered to stop work activities, make changes to enhance safety, and share the lessons learned with the organization on how we made it right.

For 2021, safety and environmental-focused goals and related metrics comprised 10 percent of our annual incentive program for employees, and included our Loss of Primary Containment Events Reduction and High Potential Near Miss to Incident Ratio.

For 2022, these goals included our Loss of Primary Containment Events Reduction, a new Behavioral Near Miss to Incident Ratio goal aimed to focus attention on behaviors that are the leading causes of incidents, as well as a new Methane Emissions Reduction goal focusing on our efforts to reduce greenhouse gas emissions. These three metrics comprise 15 percent of our annual incentive program for employees, and reinforce the importance of incident prevention and our commitment to environmental and safety-focused improvements.

For 2022, our Behavioral Near Miss to Incident Ratio and Methane Emissions Reduction goals outperformed the established targets, and while Loss of Primary Containment Events were reduced, they fell short of the overall reduction target.

Workforce Health, Engagement, and Development

Our employees are our most valued resource, are instrumental in our mission to safely deliver products that fuel the clean energy economy, and are the driving force behind our reputation as a safe, reliable company that does the right thing, every time. Cultivating a healthy work environment increases productivity and promotes long-term value creation.

We provide a comprehensive total rewards program that includes base salary, an all-employee annual incentive program, retirement benefits, and health benefits, including wellness and employee assistance programs. We provide employees with company-paid life insurance, disability coverage, and paid parental leave for both birth and non-birth parents, as well as adoption assistance. Our annual incentive program is a key component of our commitment to a performance culture focused on recognizing and rewarding high performance.

In order to attract and retain top talent, we create and are committed to maintaining a safe, inclusive workplace where employees feel valued, heard, respected, and supported in their personal and professional development. Our Employee Development Council is a cross-functional, cross-enterprise advisory board that works to understand the needs of the business by providing input on, and advocating for, employee development initiatives. Additionally, we support strong employee engagement by encouraging open dialogue regarding professional development and succession planning.

We offer robust corporate and technical training programs to support the professional development of our employees and add long-term value to our business. Our Learning and Training Council defines and maintains an agile governance structure that ensures training plans are effective and aligned to business needs and employee development. Performance is measured considering both the achieved results associated with attaining annual goals and observable skills and behaviors based on our defined competencies that contribute to workplace effectiveness and career success. Including the defined competencies in our annual performance program illustrates our emphasis on, and commitment to, achieving results in the right way.

Additionally, we are committed to strengthening the communities where we operate through philanthropic giving and volunteerism. We support Science, Technology, Engineering, and Math education initiatives, environmental conservation and first responder efforts, and the work of United Way agencies across the United States.

24

The Compensation and Management Development Committee of our Board of Directors oversees the establishment and administration of our compensation programs, including incentive compensation and equity-based plans, as well as the oversight of human capital management, including diversity and inclusion, and development.

Diversity & Inclusion

We are committed to creating an inclusive culture, where differences are embraced and employees feel valued, welcomed, appreciated, and compelled to reach their full potential. We believe that inclusion fosters innovation, collaboration, and drives business growth and long-term success. To create a culture of inclusion, we embrace, appreciate, and fully leverage the diversity within our teams, including gender, race and ethnicity, life experiences, thoughts, perspectives, and anything that makes us different from one another. We believe that incorporating our many differences into a team of people who are working toward the same goal gives us a competitive advantage.

To create space for employees to share personal experiences and perspectives, and to appreciate and celebrate what makes people different, we offer Employee Resource Groups (ERGs). These groups are employee-led and based on similar interests and experiences, represent diverse communities and their allies, and are open to everyone. ERG members participate in community events, volunteer, lend professional and personal support to one another, and promote inclusion across the company. They also provide input to the leadership team.

We are committed to helping all employees develop and succeed. We strive for diverse representation at all levels of the organization through our talent management practices and employee development programs, including required baseline diversity and inclusion training for all leaders across the company. Diversity metrics are reported monthly to our management team to enhance transparency and opportunities for improvement.

Our Diversity and Inclusion Council, which includes members of the executive officer team, organizational and operational leaders, and individual employees, promotes policies, practices, and procedures that support the growth of a high-performing workforce where all individuals can achieve their full potential. The council serves as the governing body over enterprise diversity and inclusion initiatives, including a quarterly candid conversation meeting for all employees, 10 active ERGs, and annual awards that recognize an outstanding leader and an individual contributor who champion inclusion.

As of December 31, 2022, our Board of Directors includes 12 members, 11 of whom are independent members, and one-quarter of which are women. As part of the director selection and nominating process, the Governance and Sustainability Committee annually assesses the Board’s diversity in areas such as geography, gender, race and ethnicity, and age. We strive to maintain a board of directors with diverse occupational and personal backgrounds.

WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION

We file our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, and other documents electronically with the SEC under the Exchange Act.

Our Internet website is www.williams.com. We make available, free of charge, through the Investors tab of our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8‑K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Our Corporate Governance Guidelines, Sustainability Report, Code of Ethics for Senior Officers, Board committee charters, and the Williams Code of Business Conduct are also available on our Internet website. We will also provide, free of charge, a copy of any of our corporate documents listed above upon written request to our Corporate Secretary, One Williams Center, Suite 4700, Tulsa, Oklahoma 74172.

25

Item 1A. Risk Factors

FORWARD-LOOKING STATEMENTS AND CAUTIONARY STATEMENT

FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF

THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

The reports, filings, and other public announcements of Williams may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcomes of regulatory proceedings, market conditions, and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.

All statements, other than statements of historical facts, included in this report that address activities, events, or developments that we expect, believe, or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,” “in-service date,” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:

•Levels of dividends to Williams stockholders;

•Future credit ratings of Williams and its affiliates;

•Amounts and nature of future capital expenditures;

•Expansion and growth of our business and operations;

•Expected in-service dates for capital projects;

•Financial condition and liquidity;

•Business strategy;

•Cash flow from operations or results of operations;

•Seasonality of certain business components;

•Natural gas, natural gas liquids, and crude oil prices, supply, and demand;

•Demand for our services.

Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:

•Availability of supplies, market demand, and volatility of prices;

•Development and rate of adoption of alternative energy sources;

•The impact of existing and future laws and regulations, the regulatory environment, environmental matters, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;

•Our exposure to the credit risk of our customers and counterparties;

26

•Our ability to acquire new businesses and assets and successfully integrate those operations and assets into existing businesses as well as successfully expand our facilities and consummate asset sales on acceptable terms;

•Whether we are able to successfully identify, evaluate, and timely execute our capital projects and investment opportunities;

•The strength and financial resources of our competitors and the effects of competition;

•The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;

•Whether we will be able to effectively execute our financing plan;

•Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social, and governance practices;

•The physical and financial risks associated with climate change;

•The impacts of operational and developmental hazards and unforeseen interruptions;

•The risks resulting from outbreaks or other public health crises, including COVID-19;

•Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;

•Acts of terrorism, cybersecurity incidents, and related disruptions;

•Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;

•Changes in maintenance and construction costs, as well as our ability to obtain sufficient construction- related inputs, including skilled labor;

•Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers);

•Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally recognized credit rating agencies, and the availability and cost of capital;

•The ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and other oil exporting nations to agree to and maintain oil price and production controls and the impact on domestic production;

•Changes in the current geopolitical situation, including the Russian invasion of Ukraine;

•Changes in U.S. governmental administration and policies;

•Whether we are able to pay current and expected levels of dividends;

•Additional risks described in our filings with the SEC.

Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to, and do not intend to, update the above list or announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. These factors are described in the following section.

27

RISK FACTORS

You should carefully consider the following risk factors in addition to the other information in this report. Each of these factors could adversely affect our business, prospects, financial condition, results of operations, cash flows, and, in some cases our reputation. The occurrence of any of such risks could also adversely affect the value of an investment in our securities.

Risks Related to Our Business

The financial condition of our natural gas transportation and midstream businesses is dependent on the continued availability of natural gas supplies in the supply basins that we access and demand for those supplies in the markets we serve.

Our ability to maintain and expand our natural gas transportation and midstream businesses depends on the level of drilling and production predominantly by third parties in our supply basins. Production from existing wells and natural gas supply basins with access to our pipeline and gathering systems will naturally decline over time. The amount of natural gas reserves underlying these existing wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. We do not obtain independent evaluations of natural gas reserves connected to our systems and processing facilities. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. In addition, low prices for natural gas, regulatory limitations, including permitting and environmental regulations, or the lack of available capital have, and may continue to, adversely affect the development and production of existing or additional natural gas reserves and the installation of gathering, storage, and pipeline transportation facilities. The import and export of natural gas supplies may also be affected by such conditions. Low natural gas prices in one or more of our existing supply basins, whether caused by a lack of infrastructure or otherwise, could also result in depressed natural gas production in such basins and limit the supply of natural gas made available to us. The competition for natural gas supplies to serve other markets could also reduce the amount of natural gas supply for our customers. A failure to obtain access to sufficient natural gas supplies will adversely impact our ability to maximize the capacities of our gathering, transportation, and processing facilities.

Demand for our services is dependent on the demand for gas in the markets we serve. Alternative fuel sources such as electricity, coal, fuel oils, or nuclear energy, as well as technological advances and renewable sources of energy, could reduce demand for natural gas in our markets and have an adverse effect on our business. Governmentally imposed constraints, such as prohibitions on natural gas hookups in newly constructed buildings, could also artificially limit new demand for natural gas.

A failure to obtain access to sufficient natural gas supplies or a reduction in demand for our services in the markets we serve could result in impairments of our assets and have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Prices for natural gas, NGLs, oil, and other commodities, are volatile and this volatility has and could continue to adversely affect our financial condition, results of operations, cash flows, access to capital, and ability to maintain or grow our businesses.

Our revenues, operating results, future rate of growth, and the value of certain components of our businesses depend primarily upon the prices of natural gas, NGLs, oil, or other commodities, and the differences between prices of these commodities and could be materially adversely affected by an extended period of low commodity prices, or a decline in commodity prices. Price volatility has and could continue to impact both the amount we receive for our products and services and the volume of products and services we sell. Prices affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Price volatility has had and could continue to have an adverse effect on our business, results of operations, financial condition, and cash flows.

The markets for natural gas, NGLs, oil, and other commodities are likely to continue to be volatile. Wide fluctuations in prices might result from one or more factors beyond our control, including:

•Imbalances in supply and demand whether rising from worldwide or domestic supplies of and demand for natural gas, NGLs, oil, and related commodities;

28

•Geopolitical turmoil in the Middle East, Eastern Europe, and other producing regions;

•The activities of OPEC and other countries, whether acting independently of or informally aligned with OPEC, which have significant oil, natural gas or other commodity production capabilities, including Russia;

•The level of consumer demand;

•The price and availability of other types of fuels or feedstocks;

•The availability of pipeline capacity;

•Supply disruptions, including plant outages and transportation disruptions;

•The price and quantity of foreign imports and domestic exports of natural gas and oil;

•Domestic and foreign governmental regulations and taxes;

•The credit of participants in the markets where products are bought and sold.

We are exposed to the credit risk of our customers and counterparties, and our credit risk management will not be able to completely eliminate such risk.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties in the ordinary course of our business. Generally, our customers are rated investment grade, are otherwise considered creditworthy, are required to make prepayments or provide security to satisfy credit concerns, or are dependent upon us, in some cases without a readily available alternative, to provide necessary services. However, our credit procedures and policies cannot completely eliminate customer and counterparty credit risk. Our customers and counterparties include industrial customers, local distribution companies, natural gas producers, and marketers whose creditworthiness may be suddenly and disparately impacted by, among other factors, commodity price volatility, deteriorating energy market conditions, and public and regulatory opposition to energy producing activities. In a low commodity price environment, certain of our customers have been or could be negatively impacted, causing them significant economic stress resulting, in some cases, in a customer bankruptcy filing or an effort to renegotiate our contracts. To the extent one or more of our key customers commences bankruptcy proceedings, our contracts with such customers may be subject to rejection under applicable provisions of the United States Bankruptcy Code or, if we so agree, may be renegotiated. Further, during any such bankruptcy proceeding, prior to assumption, rejection, or renegotiation of such contracts, the bankruptcy court may temporarily authorize the payment of value for our services less than contractually required, which could have a material adverse effect on our business, results of operations, cash flows, and financial condition. If we fail to adequately assess the creditworthiness of existing or future customers and counterparties or otherwise do not take sufficient mitigating actions, including obtaining sufficient collateral, deterioration in their creditworthiness and any resulting increase in nonpayment and/or nonperformance by them could cause us to write down or write off accounts receivable. Such write-downs or write-offs could negatively affect our operating results for the period in which they occur, and, if significant, could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

We face opposition to operation and expansion of our pipelines and facilities from various individuals and groups.

We have experienced, and we anticipate that we will continue to face, opposition to the operation and expansion of our pipelines and facilities from governmental officials, environmental groups, landowners, tribal groups, local groups, and other advocates. In some instances, we encounter opposition that disfavors hydrocarbon-based energy supplies regardless of practical implementation or financial considerations. Opposition to our operation and expansion can take many forms, including the delay or denial of required governmental permits, organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt, or delay the operation or expansion of our assets and business. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property, or the environment or lead to extended interruptions of our operations. Any such event that delays or prevents the expansion of our business, that interrupts the revenues generated by our operations, or which causes us to make

29

significant expenditures not covered by insurance, could adversely affect our financial condition and results of operations.

We may not be able to grow or effectively manage our growth.

As part of our growth strategy, we consider acquisition opportunities and engage in significant capital projects. We have both a project lifecycle process and an investment evaluation process. These are processes we use to identify, evaluate, and execute on acquisition opportunities and capital projects. We may not always have sufficient and accurate information to identify and value potential opportunities and risks or our investment evaluation process may be incomplete or flawed. Regarding potential acquisitions, suitable acquisition candidates or assets may not be available on terms and conditions we find acceptable or, where multiple parties are trying to acquire an acquisition candidate or assets, we may not be chosen as the acquirer. If we are able to acquire a targeted business, we may not be able to successfully integrate the acquired businesses and realize anticipated benefits in a timely manner.

Our growth may also be dependent upon the construction of new natural gas gathering, transportation, compression, processing, or treating pipelines and facilities, NGL transportation, or fractionation or storage facilities as well as the expansion of existing facilities. Additional risks associated with construction may include the inability to obtain rights-of-way, skilled labor, equipment, materials, permits, and other required inputs in a timely manner such that projects are completed, on time or at all, and the risk that construction cost overruns, including due to inflation, could cause total project costs to exceed budgeted costs. Additional risks associated with growing our business include, among others, that:

•Changing circumstances and deviations in variables could negatively impact our investment analysis, including our projections of revenues, earnings, and cash flow relating to potential investment targets, resulting in outcomes that are materially different than anticipated;

•We could be required to contribute additional capital to support acquired businesses or assets, and we may assume liabilities that were not disclosed to us, that exceed our estimates and for which contractual protections are either unavailable or prove inadequate;

•Acquisitions could disrupt our ongoing business, distract management, divert financial and operational resources from existing operations, and make it difficult to maintain our current business standards, controls, and procedures;

•Acquisitions and capital projects may require substantial new capital, including the issuance of debt or equity, and we may not be able to access credit or capital markets or obtain acceptable terms.

If realized, any of these risks could have an adverse impact on our financial condition, results of operations, including the possible impairment of our assets, or cash flows.

Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results.

We have numerous competitors in all aspects of our businesses, and additional competitors may enter our markets. Any current or future competitor that delivers natural gas, NGLs, or other commodities into the areas that we operate could offer transportation services that are more desirable to shippers than those we provide because of price, location, facilities, or other factors. In addition, current or potential competitors may make strategic acquisitions or have greater financial resources than we do, which could affect our ability to make strategic investments or acquisitions. Our competitors may be able to respond more quickly to new laws or regulations or emerging technologies or to devote greater resources to the construction, expansion, or refurbishment of their facilities than we can. Failure to successfully compete against current and future competitors could have a material adverse effect on our business, results of operations, financial condition, and cash flows.

We do not own 100 percent of the equity interests of certain subsidiaries, including the Nonconsolidated Entities, which may limit our ability to operate and control these subsidiaries. Certain operations, including the Nonconsolidated Entities, are conducted through arrangements that may limit our ability to operate and control these operations.

The operations of our current non-wholly-owned subsidiaries, including the Nonconsolidated Entities, are conducted in accordance with their organizational documents. We anticipate that we will enter into more such

30

arrangements, including through new joint venture structures or new Nonconsolidated Entities. We may have limited operational flexibility in such current and future arrangements, and we may not be able to control the timing or amount of cash distributions received. In certain cases:

•We cannot control the amount of cash reserves determined to be necessary to operate the business, which reduces cash available for distributions;

•We cannot control the amount of capital expenditures that we are required to fund and we are dependent on third parties to fund their required share of capital expenditures;

•We may be subject to restrictions or limitations on our ability to sell or transfer our interests in the jointly owned assets;

•We may be forced to offer rights of participation to other joint venture participants in the area of mutual interest;

•We have limited ability to influence or control certain day to day activities affecting the operations;

•We may have additional obligations, such as required capital contributions, that are important to the success of the operations.

In addition, conflicts of interest may arise between us, on the one hand, and other interest owners, on the other hand. If such conflicts of interest arise, we may not have the ability to control the outcome with respect to the matter in question. Disputes between us and other interest owners may also result in delays, litigation, or operational impasses.

The risks described above or the failure to continue such arrangements could adversely affect our ability to conduct the operations that are the subject of such arrangements which could, in turn, negatively affect our business, growth strategy, financial condition, and results of operations.

We may not be able to replace, extend, or add additional customer contracts or contracted volumes on favorable terms, or at all, which could affect our financial condition, the amount of cash available to pay dividends, and our ability to grow.

We rely on a limited number of customers and producers for a significant portion of our revenues and supply of natural gas and NGLs. Although many of our customers and suppliers are subject to long-term contracts, if we are unable to replace or extend such contracts, add additional customers, or otherwise increase the contracted volumes of natural gas provided to us by current producers, in each case on favorable terms, if at all, our financial condition, growth plans, and the amount of cash available to pay dividends could be adversely affected. Our ability to replace, extend, or add additional customer or supplier contracts, or increase contracted volumes of natural gas from current producers, on favorable terms, or at all, is subject to a number of factors, some of which are beyond our control, including:

•The level of existing and new competition in our businesses or from alternative sources, such as electricity, renewable resources, coal, fuel oils, or nuclear energy;

•Natural gas and NGL prices, demand, availability, and margins in our markets. Higher prices for energy commodities related to our businesses could result in a decline in the demand for those commodities and, therefore, in customer contracts or throughput on our pipeline systems. Also, lower energy commodity prices could negatively impact our ability to maintain or achieve favorable contractual terms, including pricing, and could also result in a decline in the production of energy commodities resulting in reduced customer contracts, supply contracts, and throughput on our pipeline systems;

•General economic, financial markets, and industry conditions;

•The effects of regulation on us, our customers, and our contracting practices;

•Our ability to understand our customers’ expectations, efficiently and reliably deliver high quality services, and effectively manage customer relationships. The results of these efforts will impact our reputation and positioning in the market.

31

Certain of our gas pipeline services are subject to long-term, fixed-price contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.

Our gas pipelines provide some services pursuant to long-term, fixed-price contracts. It is possible that costs to perform services under such contracts will exceed the revenues our pipelines collect for their services. Although other services are priced at cost-based rates that are subject to adjustment in rate cases, under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” that may be above or below the FERC regulated cost-based rate for that service. These “negotiated rate” contracts are not generally subject to adjustment for increased costs that could be produced by inflation or other factors relating to the specific facilities being used to perform the services.

Some of our businesses are exposed to supplier concentration risks arising from dependence on a single or a limited number of suppliers.

Some of our businesses may be dependent on a small number of suppliers for delivery of critical goods or services. If a supplier on which one of our businesses depends were to fail to timely supply required goods and services, such business may not be able to replace such goods and services in a timely manner or otherwise on favorable terms or at all. If our business is unable to adequately diversify or otherwise mitigate such supplier concentration risks and such risks were realized, such businesses could be subject to reduced revenues and increased expenses, which could have a material adverse effect on our financial condition, results of operation, and cash flows.

Failure of our service providers or disruptions to our outsourcing relationships might negatively impact our ability to conduct our business.

Certain of our accounting and information technology services are currently provided by third-party vendors, and sometimes from service centers outside of the United States. Services provided pursuant to these arrangements could be disrupted. Similarly, the expiration of agreements associated with such arrangements or the transition of services between providers could lead to loss of institutional knowledge or service disruptions. Our reliance on others as service providers could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

An impairment of our assets, including property, plant, and equipment, intangible assets, and/or equity-method investments, could reduce our earnings.

GAAP requires us to test certain assets for impairment on either an annual basis or when events or circumstances occur which indicate that the carrying value of such assets might be impaired. The outcome of such testing could result in impairments of our assets including our property, plant, and equipment, intangible assets, and/or equity-method investments. Additionally, any asset monetizations could result in impairments if any assets are sold or otherwise exchanged for amounts less than their carrying value. If we determine that an impairment has occurred, we would be required to take an immediate noncash charge to earnings.

Increasing scrutiny and changing expectations from stakeholders with respect to our environmental, social and governance practices may impose additional costs on us or expose us to new or additional risks.

Companies across all industries are facing increasing scrutiny from stakeholders related to their environmental, social and governance (“ESG”) practices. Investor advocacy groups, institutional investors, investment funds and other influential investors are also increasingly focused on ESG practices and in recent years have placed increasing importance on the implications and social cost of their investments. Regardless of the industry, investors’ increased focus and activism related to ESG (as proponents or opponents) and similar matters may hinder access to capital, as investors may decide to reallocate capital or to not commit capital as a result of their assessment of a company’s ESG practices. Companies that do not adapt to or comply with investor or other stakeholder expectations and standards, which are evolving, or that are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, may suffer from reputational damage, and the business, financial condition, and/or stock price of such a company could be materially and adversely affected.

We face pressures from our stockholders, who are increasingly focused on climate change, to prioritize sustainable energy practices, reduce our carbon footprint, and promote sustainability. Our stockholders may require us to implement ESG procedures or standards in order to continue engaging with us, to remain invested in us or before they may make further investments in us. Additionally, we may face reputational challenges in the event our

32

ESG procedures or standards do not meet the standards set by certain constituencies. We adopted certain practices as highlighted in our 2021 Sustainability Report, including with respect to air emissions, biodiversity and land use, climate change, and environmental stewardship. It is possible, however, that our stockholders might not be satisfied with our sustainability efforts or the speed of their adoption. If we do not meet our stockholders’ expectations, our business, ability to access capital, and/or our stock price could be harmed.

Additionally, adverse effects upon the oil and gas industry related to the worldwide social and political environments, including uncertainty or instability resulting from climate change, changes in political leadership and environmental policies, changes in geopolitical-social views toward fossil fuels and renewable energy, concern about the environmental impact of climate change, and investors’ expectations regarding ESG matters, may also adversely affect demand for our services. Any long-term material adverse effect on the oil and gas industry could have a significant financial and operational adverse impact on our business.

The occurrence of any of the foregoing could have a material adverse effect on the price of our stock and our business and financial condition.

We may be subject to physical and financial risks associated with climate change.

The threat of global climate change may create physical and financial risks to our business. Energy needs vary with weather conditions. To the extent weather conditions may be affected by climate change, energy use could increase or decrease depending on the duration and magnitude of any changes. Increased energy use due to weather changes may require us to invest in more pipelines and other infrastructure to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of our operating territory could also have an impact on our revenues. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. We may not be able to pass on the higher costs to our customers or recover all costs related to mitigating these physical risks.

Additionally, many climate models indicate that global warming is likely to result in rising sea levels and increased frequency and severity of weather events, which may lead to higher insurance costs, or a decrease in available coverage, for our assets in areas subject to severe weather. These climate-related changes could damage our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone and rain-susceptible regions.

To the extent financial markets view climate change and greenhouse gas (“GHG”) emissions as a financial risk, this could negatively impact our cost of and access to capital. Climate change and GHG regulation could also reduce demand for our services. Our business could also be affected by the potential for lawsuits against GHG emitters, based on links drawn between GHG emissions and climate change.

Our operations are subject to operational hazards and unforeseen interruptions.

There are operational risks associated with the gathering, transporting, storage, processing, and treating of natural gas, the fractionation, transportation, and storage of NGLs, and crude oil transportation and production handling, including:

•Aging infrastructure and mechanical problems;

•Damages to pipelines and pipeline blockages or other pipeline interruptions;

•Uncontrolled releases of natural gas (including sour gas), NGLs, crude oil, or other products;

•Collapse or failure of storage caverns;

•Operator error;

•Damage caused by third-party activity, such as operation of construction equipment;

•Pollution and other environmental risks;

•Fires, explosions, craterings, and blowouts;

33

•Security risks, including cybersecurity;

•Operating in a marine environment.

Any of these risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations, loss of services to our customers, reputational damage, and substantial losses to us. The location of certain segments of our facilities in or near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. An event such as those described above could have a material adverse effect on our financial condition and results of operations, particularly if the event is not fully covered by insurance.

Our assets and operations, as well as our customers’ assets and operations, can be adversely affected by weather and other natural phenomena.

Our assets and operations, especially those located offshore, and our customers’ assets and operations can be adversely affected by hurricanes, floods, earthquakes, landslides, tornadoes, fires, and other natural phenomena and weather conditions, including extreme or unseasonable temperatures, making it more difficult for us to realize the historic rates of return associated with our assets and operations. A significant disruption in our or our customers’ operations or the occurrence of a significant liability for which we are not fully insured could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Our business could be negatively impacted by acts of terrorism and related disruptions.

Given the volatile nature of the commodities we transport, process, store, and sell, our assets and the assets of our customers and others in our industry may be targets of terrorist activities. Uncertainty surrounding the Russian invasion of Ukraine, or other sustained military campaigns, may affect our operations in unpredictable ways, including the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terrorism. A terrorist attack could create significant price volatility, disrupt our business, limit our access to capital markets, or cause significant harm to our operations, such as full or partial disruption to our ability to produce, process, transport, or distribute natural gas, NGLs, or other commodities. Acts of terrorism, as well as events occurring in response to or in connection with acts of terrorism, could cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

A breach of our information technology infrastructure, including a breach caused by a cybersecurity attack on us or third parties with whom we are interconnected, may interfere with the safe operation of our assets, result in the disclosure of personal or proprietary information, and harm our reputation.

We rely on our information technology infrastructure to process, transmit, and store electronic information, including information we use to safely operate our assets. Our Board of Directors has oversight responsibility with regard to assessment of the major risks inherent in our business, including cybersecurity risks, and reviews management’s efforts to address and mitigate such risks, including the establishment and implementation of policies to address cybersecurity threats. We have invested, and expect to continue to invest, significant time, manpower, and capital in our information technology infrastructure. However, the age, operating systems, or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cybersecurity threats. While we believe that we maintain appropriate information security policies, practices, and protocols, we regularly face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational industrial control systems and safety systems that operate our pipelines, plants, and assets. We face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists”, or private individuals. We face the threat of theft and misuse of sensitive data and information, including customer and employee information. We also face attempts to gain access to information related to our assets through attempts to obtain unauthorized access by targeting acts of deception against individuals with legitimate access to physical locations or information. We also are subject to cybersecurity risks arising from the fact that our business operations are interconnected with third parties, including third-party pipelines, other facilities and our contractors and vendors. In addition, the breach of certain business systems could affect our ability to correctly record, process, and report financial information. Breaches in our information technology infrastructure or physical

34

facilities, or other disruptions including those arising from theft, vandalism, fraud, or unethical conduct, which may increase as a result of the Russian invasion of Ukraine, could result in damage to or destruction of our assets, unnecessary waste, safety incidents, damage to the environment, reputational damage, potential liability, the loss of contracts, the imposition of significant costs associated with remediation and litigation, heightened regulatory scrutiny, increased insurance costs, and have a material adverse effect on our operations, financial condition, results of operations, and cash flows.

If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas and NGLs or to treat natural gas, our revenues could be adversely affected.

We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines and facilities for the benefit of our customers. Because we do not own these third-party pipelines or other facilities, their continuing operation is not within our control. If these pipelines or facilities were to become temporarily or permanently unavailable for any reason, or if throughput were reduced because of testing, line repair, damage to pipelines or facilities, reduced operating pressures, lack of capacity, increased credit requirements or rates charged by such pipelines or facilities or other causes, we and our customers would have reduced capacity to transport, store, or deliver natural gas or NGL products to end use markets or to receive deliveries of mixed NGLs, thereby reducing our revenues. Any temporary or permanent interruption at any key pipeline interconnection or in operations on third-party pipelines or facilities that would cause a material reduction in volumes transported on our pipelines or our gathering systems or processed, fractionated, treated, or stored at our facilities could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Our operating results for certain components of our business might fluctuate on a seasonal basis.

Revenues from certain components of our business can have seasonal characteristics. In many parts of the country, demand for natural gas and other fuels peaks during the winter. As a result, our overall operating results in the future might fluctuate substantially on a seasonal basis. Demand for natural gas and other fuels could vary significantly from our expectations depending on the nature and location of our facilities and pipeline systems and the terms of our natural gas transportation arrangements relative to demand created by unusual weather patterns.

We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.

We do not own all of the land on which our pipelines and facilities have been constructed. As such, we are subject to the possibility of increased costs to retain necessary land use. In those instances in which we do not own the land on which our facilities are located, we obtain the rights to construct and operate our facilities and gathering systems on land owned by third parties and governmental agencies for a specific period of time. In addition, some of our facilities cross Native American lands pursuant to rights-of-way of limited terms. We may not have the right of eminent domain over land owned by Native American tribes. Our loss of any of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Our business could be negatively impacted as a result of stockholder activism.

In recent years, stockholder activism, including threatened or actual proxy contests, has been directed against numerous public companies, including ours. We were the target of a proxy contest from a stockholder activist, which resulted in our incurring significant costs. If stockholder activists were to again take or threaten to take actions against the Company or seek to involve themselves in the governance, strategic direction, or operations of the Company, we could incur significant costs as well as the distraction of management, which could have an adverse effect on our business or financial results. In addition, actions of activist stockholders may cause significant fluctuations in our stock price based on temporary or speculative market perceptions or other factors that do not necessarily reflect the underlying fundamentals and prospects of our business.

Our costs and funding obligations for our defined benefit pension plans and costs for our other postretirement benefit plans are affected by factors beyond our control.

We have defined benefit pension plans and other postretirement benefit plans. The timing and amount of our funding requirements under the defined benefit pension plans depend upon a number of factors that we control, including changes to pension plan benefits, as well as factors outside of our control, such as asset returns, interest

35

rates, and changes in pension laws. Changes to these and other factors that can significantly increase our funding requirements could have a significant adverse effect on our financial condition and results of operations.

Risks Related to Financing Our Business

A downgrade of our credit ratings, which are determined outside of our control by independent third parties, could impact our liquidity, access to capital, and our costs of doing business.

Downgrades of our credit ratings increase our cost of borrowing and could require us to provide collateral to our counterparties, negatively impacting our available liquidity. In addition, our ability to access capital markets could be limited by the downgrading of our credit ratings.

Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria such as, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are subject to revision or withdrawal at any time by the ratings agencies. As of the date of the filing of this report, we have been assigned an investment-grade credit rating by the credit ratings agencies.

Difficult conditions in the global financial markets and the economy in general could negatively affect our business and results of operations.

Our businesses may be negatively impacted by adverse economic conditions or future disruptions in the global financial markets. Included among these potential negative impacts are industrial or economic contraction (including as a result of the COVID-19 pandemic) leading to reduced energy demand and lower prices for our products and services and increased difficulty in collecting amounts owed to us by our customers. The ongoing Russian invasion of Ukraine and the actions undertaken by western nations in response to Russia’s actions has had, and may continue to have, adverse impacts on global financial markets. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures. In addition, financial markets have periodically been affected by concerns over U.S. fiscal and monetary policies. These concerns, as well as actions taken by the U.S. federal government in response to these concerns, could significantly and adversely impact the global and U.S. economies and financial markets, which could negatively impact us in the manner described above.

Restrictions in our debt agreements and the amount of our indebtedness may affect our future financial and operating flexibility.

Our total outstanding long-term debt (including current portion) as of December 31, 2022, was $22.6 billion.

The agreements governing our indebtedness contain covenants that restrict our and our material subsidiaries’ ability to incur certain liens to support indebtedness and our ability to merge or consolidate or sell all or substantially all of our assets in certain circumstances. In addition, certain of our debt agreements contain various covenants that restrict or limit, among other things, our ability to make certain distributions during the continuation of an event of default, the ability of our subsidiaries to incur additional debt, and our, and our material subsidiaries’, ability to enter into certain affiliate transactions and certain restrictive agreements. Certain of our debt agreements also contain, and those we enter into in the future may contain, financial covenants, and other limitations with which we will need to comply.

Our debt service obligations and the covenants described above could have important consequences. For example, they could:

•Make it more difficult for us to satisfy our obligations with respect to our indebtedness, which could in turn result in an event of default on such indebtedness;

•Impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes, or other purposes;

•Diminish our ability to withstand a continued or future downturn in our business or the economy generally;

36

•Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, the payments of dividends, general corporate purposes, or other purposes;

•Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate, including limiting our ability to expand or pursue our business activities and preventing us from engaging in certain transactions that might otherwise be considered beneficial to us.

Our ability to comply with our debt covenants, to repay, extend, or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance. Our ability to refinance existing debt obligations or obtain future credit will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to comply with these covenants, meet our debt service obligations, or obtain future credit on favorable terms, or at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.

Our failure to comply with the covenants in the documents governing our indebtedness could result in events of default, which could render such indebtedness due and payable. We may not have sufficient liquidity to repay our indebtedness in such circumstances. In addition, cross-default or cross-acceleration provisions in our debt agreements could cause a default or acceleration to have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. For more information regarding our debt agreements, please read Note 12 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements.

Changes to interest rates or increases in interest rates could adversely impact our access to credit, share price, our ability to issue securities or incur debt for acquisitions or other purposes, and our ability to make cash dividends at our intended levels.

Interest rates may increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our share price will be impacted by the level of our dividends and implied dividend yield. The dividend yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our shares, and a rising interest rate environment could have an adverse impact on our share price and our ability to issue equity or incur debt for acquisitions or other purposes and to pay cash dividends at our intended levels.

Our hedging activities might not be effective and could increase the volatility of our results.

In an effort to manage our financial exposure related to commodity price and market fluctuations, we have entered, and may in the future enter into contracts to hedge certain risks associated with our assets and operations. In these hedging activities, we have used, and may in the future use, fixed-price, forward, physical purchase, and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. Nevertheless, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist. While we attempt to manage counterparty credit risk within guidelines established by our credit policy, we may not be able to successfully manage all credit risk and as such, future cash flows and results of operations could be impacted by counterparty default. The difference in accounting treatment for the underlying position and the financial instrument used to hedge the value of the contract can cause volatility in our reported net income while the positions are open due to mark-to-market accounting.

Our and our customers’ access to capital could be affected by financial institutions’ policies concerning fossil- fuel related businesses.

Public concern regarding the potential effects of climate change have directed increased attention towards the funding sources of fossil-fuel energy companies. As a result, certain financial institutions, funds, and other sources of capital have restricted or eliminated their investment in certain market segments of fossil-fuel related energy. Ultimately, limiting fossil-fuel related companies’ access to capital could make it more difficult for our customers to

37

secure funding for exploration and production activities or for us to secure funding for growth projects. Such a lack of capital could also both indirectly affect demand for our services and directly affect our ability to fund construction or other capital projects.

Risks Related to Regulations

The operation of our businesses might be adversely affected by regulatory proceedings, changes in government regulations or in their interpretation or implementation, or the introduction of new laws or regulations applicable to our businesses or our customers.

Public and regulatory scrutiny of the energy industry has resulted in the proposal and/or implementation of increased regulations. Such scrutiny has also resulted in various inquiries, investigations, and court proceedings, including litigation of energy industry matters. Both the shippers on our pipelines and regulators have rights to challenge the rates we charge under certain circumstances. Any successful challenge could materially affect our results of operations.

Certain inquiries, investigations, and court proceedings are ongoing. Adverse effects may continue as a result of the uncertainty of ongoing inquiries, investigations, and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines and/or penalties, or other regulatory action, including legislation, which might be materially adverse to the operation of our business and our results of operations or increase our operating costs in other ways. Current legal proceedings or other matters, including environmental matters, suits, regulatory appeals, and similar matters might result in adverse decisions against us which, among other outcomes, could result in the imposition of substantial penalties and fines and could damage our reputation. The result of such adverse decisions, either individually or in the aggregate, could be material and may not be covered fully or at all by insurance.

In addition, existing regulations, including those pertaining to financial assurances to be provided by our businesses in respect of potential asset decommissioning and abandonment activities, might be revised, reinterpreted, or otherwise enforced in a manner that differs from prior regulatory action. New laws and regulations, including those pertaining to oil and gas hedging and cash collateral requirements, might also be adopted or become applicable to us, our customers, or our business activities. The change in the U.S. governmental administration and its policies may increase the likelihood of such legal and regulatory developments. If new laws or regulations are imposed relating to oil and gas extraction, or if additional or revised levels of reporting, regulation, or permitting moratoria are required or imposed, including those related to hydraulic fracturing, the volumes of natural gas and other products that we transport, gather, process, and treat could decline, our compliance costs could increase, and our results of operations could be adversely affected.

The natural gas sales, transportation, and storage operations of our gas pipelines are subject to regulation by the FERC, which could have an adverse impact on their ability to establish transportation and storage rates that would allow them to recover the full cost of operating their respective pipelines and storage assets, including a reasonable rate of return.

In addition to regulation by other federal, state, and local regulatory authorities, interstate pipeline transportation and storage service is subject to regulation by the FERC. Federal regulation extends to such matters as:

•Transportation and sale for resale of natural gas in interstate commerce;

•Rates, operating terms, types of services, and conditions of service;

•Certification and construction of new interstate pipelines and storage facilities;

•Acquisition, extension, disposition, or abandonment of existing interstate pipelines and storage facilities;

•Accounts and records;

•Depreciation and amortization policies;

•Relationships with affiliated companies that are involved in marketing functions of the natural gas business;

•Market manipulation in connection with interstate sales, purchases, or transportation of natural gas.

38

Regulatory or administrative actions in these areas, including successful complaints or protests against the rates of the gas pipelines, can affect our business in many ways, including decreasing tariff rates and revenues, decreasing volumes in our pipelines, increasing our costs, and otherwise altering the profitability of our pipeline business.

Our operations are subject to environmental laws and regulations, including laws and regulations relating to climate change and greenhouse gas emissions, which may expose us to significant costs, liabilities, and expenditures that could exceed our expectations.

Our operations are subject to extensive federal, state, tribal, and local laws and regulations governing environmental protection, endangered and threatened species, the discharge of materials into the environment, and the security of chemical and industrial facilities. Substantial costs, liabilities, delays, and other significant issues related to environmental laws and regulations are inherent in the gathering, transportation, storage, processing, and treating of natural gas, fractionation, transportation, and storage of NGLs, and crude oil transportation and production handling as well as waste disposal practices and construction activities. New or amended environmental laws and regulations can also result in significant increases in capital costs we incur to comply with such laws and regulations. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, and delays or denials in granting permits.

Joint and several strict liability may be incurred without regard to fault under certain environmental laws and regulations, for the remediation of contaminated areas and in connection with spills or releases of materials associated with natural gas, oil, and wastes on, under, or from our properties and facilities. Private parties, including the owners of properties through which our pipeline and gathering systems pass and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate are located near current or former third-party hydrocarbon storage and processing or oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours.

We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest, or alter the operation of those facilities, which might cause us to incur losses.

In addition, climate change regulations and the costs that may be associated with such regulations and with the regulation of emissions of GHGs have the potential to affect our business. Regulatory actions by the Environmental Protection Agency or the passage of new climate change laws or regulations could result in increased costs to operate and maintain our facilities, install new emission controls on our facilities, or administer and manage any GHG emissions program. We believe it is possible that future governmental legislation and/or regulation may require us either to limit GHG emissions associated with our operations or to purchase allowances for such emissions. We could also be subjected to a carbon tax assessed on the basis of carbon dioxide emissions or otherwise. However, we cannot predict precisely what form these future regulations might take, the stringency of any such regulations or when they might become effective. Several legislative bills have been introduced in the United States Congress that would require carbon dioxide emission reductions. Previously considered proposals have included, among other things, limitations on the amount of GHGs that can be emitted (so called “caps”) together with systems of permitted emissions allowances. These proposals could require us to reduce emissions or to purchase allowances for such emissions.

In addition to activities on the federal level, state and regional initiatives could also lead to the regulation of GHG emissions sooner than and/or independent of federal regulation. These regulations could be more stringent than any federal legislation that may be adopted. Future legislation and/or regulation designed to reduce GHG emissions could make some of our activities uneconomic to maintain or operate. We continue to monitor legislative and regulatory developments in this area and otherwise take efforts to limit and reduce GHG emissions from our

39

facilities. Although the regulation of GHG emissions may have a material impact on our operations and rates, we believe it is premature to attempt to quantify the potential costs of the impacts.

If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition.

General Risk Factors

We do not insure against all potential risks and losses and could be seriously harmed by unexpected liabilities or by the inability of our insurers to satisfy our claims.

In accordance with customary industry practice, we maintain insurance against some, but not all, risks and losses, and only at levels we believe to be appropriate. The occurrence of any risks not fully covered by our insurance could have a material adverse effect on our business, financial condition, results of operations, and cash flows and our ability to repay our debt.

Failure to attract and retain an appropriately qualified workforce could negatively impact our results of operations.

Events such as an aging workforce without appropriate replacements, mismatch of skill sets to future needs, the challenges of attracting new, qualified workers to the midstream energy industry, or unavailability of contract labor may lead to operating challenges such as lack of resources, loss of knowledge, and a lengthy time period associated with skill development, including with the workforce needs associated with projects and ongoing operations. Failure to hire and adequately obtain replacement employees, including the ability to transfer significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect our ability to manage and operate the businesses. If we are unable to successfully attract and retain an appropriately qualified workforce, including members of senior management, results of operations could be negatively impacted.

Holders of our common stock may not receive dividends in the amount expected or any dividends.

We may not have sufficient cash each quarter to pay dividends or maintain current or expected levels of dividends. The actual amount of cash we dividend may fluctuate from quarter to quarter and will depend on various factors, some of which are beyond our control, including:

•The amount of cash that our subsidiaries distribute to us;

•The amount of cash we generate from our operations, our working capital needs, our level of capital expenditures, and our ability to borrow;

•The restrictions contained in our indentures and credit facility and our debt service requirements;

•The cost of acquisitions, if any.

A failure either to pay dividends or to pay dividends at expected levels could result in a loss of investor confidence, reputational damage, and a decrease in the value of our stock price.

Item 1B. Unresolved Staff Comments

Not applicable.

Item 2. Properties

Please read “Business” for a description of the location and general character of our principal physical properties. We generally own our facilities, although a substantial portion of our pipeline and gathering facilities is constructed and maintained pursuant to rights-of-way, easements, permits, licenses, or consents on and across properties owned by others.

40

Item 3. Legal Proceedings

Environmental

Certain reportable legal proceedings involving governmental authorities under federal, state, and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings that are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings. Our threshold for disclosing material environmental legal proceedings involving a governmental authority where potential monetary sanctions are involved is $1 million.

On January 19, 2016, we received a Notice of Noncompliance with certain Leak Detection and Repair (LDAR) regulations under the Clean Air Act at our Moundsville Fractionator Facility from the EPA, Region 3. Subsequently, the EPA alleged similar violations of certain LDAR regulations at our Oak Grove Gas Plant. On March 19, 2018, we received a Notice of Violation of certain LDAR regulations at our former Ignacio Gas Plant from the EPA, Region 8, following an on-site inspection of the facility. On March 20, 2018, we also received a Notice of Violation of certain LDAR regulations at our Parachute Creek Gas Plant from the EPA, Region 8. All such notices were subsequently referred to a common attorney at the Department of Justice (DOJ). We have reached an agreement in principle with the DOJ and other agencies regarding global resolution of the claims at these facilities, as well as alleged violations at certain other facilities. The proposed global resolution includes both payment of a civil penalty in the amount of $3.75 million and an injunctive relief component. We continue to work with the DOJ and the other agencies towards finalization of the global resolution.

Other environmental matters called for by this Item are described under the caption “Environmental Matters” in Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements included under Part II, Item 8 Financial Statements of this report, which information is incorporated by reference into this Item.

Other litigation

The additional information called for by this Item is provided in Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements included under Part II, Item 8 Financial Statements of this report, which information is incorporated by reference into this Item.

Item 4. Mine Safety Disclosures

Not applicable.

41

Information About Our Executive Officers

The name, title, age, period of service, and recent business experience of each of our executive officers as of February 27, 2023, are listed below.

Name and Position	Age	Business Experience in Past Five Years
Alan S. Armstrong	60	2011 to present	Director, Chief Executive Officer, and President, The Williams Companies, Inc.
Director, Chief Executive Officer, and President		2015 to 2018	Chairman of the Board, Williams Partners L.P.
		2014 to 2018	Chief Executive Officer, Williams Partners L.P.
		2012 to 2018	Director of the general partner, Williams Partners L.P.
Debbie Cowan	45	2018 to present	Senior Vice President and Chief Human Resources Officer, The Williams Companies, Inc.
Senior Vice President and Chief Human Resources Officer		2013 to 2018	Global Vice President of Human Resources, Koch Chemical Technology Group, LLC
Micheal G. Dunn	57	2017 to present	Executive Vice President and Chief Operating Officer, The Williams Companies, Inc.
Executive Vice President and Chief Operating Officer		2017 to 2018	Director of the general partner, Williams Partners L.P.
Scott A. Hallam	46	2020 to present	Senior Vice President Transmission & Gulf of Mexico, The Williams Companies, Inc.
Senior Vice President Transmission & Gulf of Mexico		2019	Senior Vice President – Atlantic-Gulf, The Williams Companies, Inc.
		2017 to 2019	Vice President GM Atlantic-Gulf, The Williams Companies, Inc.
		2015 to 2017	Vice President Northeast OA, The Williams Companies, Inc.
Mary A. Hausman	51	2022 to present	Vice President, Chief Accounting Officer and Controller, The Williams Companies, Inc.
Vice President, Chief Accounting Officer and Controller		2019 to 2022	Staff Vice President of Internal Audit, The Williams Companies, Inc.
		2019	Director Special Projects, The Williams Companies, Inc.
		2013 to 2019	Vice President and Chief Accounting Officer, NV Energy (a Berkshire Hathaway Energy Company)
Larry C. Larsen	48	2022 to present	Senior Vice President Gathering & Processing, The Williams Companies, Inc.
Senior Vice President Gathering & Processing		2020 to 2021	Vice President Strategic Development, The Williams Companies, Inc.
		2019 to 2020	Vice President Rocky Mountain Midstream, The Williams Companies, Inc.
		2018 to 2019	Vice President GM Rocky Mountain Midstream, The Williams Companies, Inc.
		2017 to 2018	Vice President Central Services, The Williams Companies, Inc.

42

Name and Position	Age	Business Experience in Past Five Years
John D. Porter	53	2022 to present	Senior Vice President and Chief Financial Officer, The Williams Companies, Inc.
Senior Vice President and Chief Financial Officer		2020 to 2021	Vice President, Chief Accounting Officer, Controller and Financial Planning & Analysis, The Williams Companies, Inc.
		2017 to 2019	Vice President Enterprise Financial Planning & Analysis and Investor Relations, The Williams Companies, Inc.
		2013 to 2017	Director of Investor Relations & Enterprise Planning, The Williams Companies, Inc.
Chad A. Teply	51	2020 to present	Senior Vice President – Project Execution, The Williams Companies, Inc.
Senior Vice President – Project Execution		2017 to 2020	Senior Vice President – Business Policy and Development, PacifiCorp (a Berkshire Hathaway Energy Company)
		2009 to 2017	Vice President – Resource Development and Construction, PacifiCorp (a Berkshire Hathaway Energy Company)
T. Lane Wilson	56	2017 to present	Senior Vice President and General Counsel, The Williams Companies, Inc.
Senior Vice President and General Counsel		2009 to 2017	United States Magistrate Judge for the Northern District of Oklahoma
Chad J. Zamarin	46	2023 to present	Executive Vice President of Corporate Strategic Development, The Williams Companies, Inc.
Executive Vice President of Corporate Strategic Development		2017 to 2023	Senior Vice President – Corporate Strategic Development, The Williams Companies, Inc.
		2017 to 2018	Director of the general partner, Williams Partners L.P.
		2014 to 2017	President – Pipeline and Midstream, Cheniere Energy

43

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is listed on the New York Stock Exchange under the symbol “WMB.” At the close of business on February 17, 2023, we had 6,013 holders of record of our common stock.

Share Repurchase Program

ISSUER PURCHASES OF EQUITY SECURITIES
Period	(a) Total Number of Shares Purchased	(b) Average Price Paid Per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1)	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
October 1 - October 31, 2022	—	$	—	—	$	1,491,248,057
November 1 - November 30, 2022	—	$	—	—	$	1,491,248,057
December 1 - December 31, 2022	—	$	—	—	$	1,491,248,057
Total	—			—

(1)We announced a stock repurchase program on September 8, 2021. Our board of directors has authorized the repurchase of up to $1.5 billion of the company’s common stock. The stock repurchase program has no expiration date. We intend to purchase shares of our stock from time to time in open market transactions, block purchases, privately negotiated or structured transactions, or in such other manner as determined at our discretion, subject to market conditions and other factors.

Performance Graph

Set forth below is a line graph comparing our cumulative total stockholder return on our common stock (assuming reinvestment of dividends) with the cumulative total return of the S&P 500 Stock Index, the Bloomberg Americas Pipelines Index, and the Arca Natural Gas Index for the period of five fiscal years commencing January 1, 2018. The Bloomberg Americas Pipelines Index is composed of Enbridge Inc., TC Energy Corporation, Kinder Morgan, Inc., ONEOK, Inc., Cheniere Energy, Inc., Pembina Pipeline Corporation, Targa Resources Corp., New Fortress Energy Inc., and Williams. The Arca Natural Gas Index is comprised of over 20 highly capitalized companies in the natural gas industry involved primarily in natural gas exploration and production and natural gas pipeline transportation and transmission. The graph below assumes an investment of $100 at the beginning of the period.

44

	2017	2018	2019	2020	2021	2022
The Williams Companies, Inc.	100.0	74.5	85.1	78.7	108.9	144.8
S&P 500 Index	100.0	94.8	124.7	147.6	189.9	155.5
Bloomberg Americas Pipelines Index	100.0	83.8	113.4	89.7	120.3	139.0
Arca Natural Gas Index	100.0	66.4	65.5	56.7	91.0	116.5

45

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

We are an energy company committed to being the leader in providing infrastructure that safely delivers natural gas products to reliably fuel the clean energy economy. Our operations are located in the United States.

Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high-quality, low-cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established primarily through the FERC’s ratemaking process, but we also may negotiate rates with our customers pursuant to the terms of our tariffs and FERC policy. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.

The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing, treating, compression, and storage, NGL fractionation, transportation and storage, crude oil production handling and transportation, as well as marketing services for NGL, crude oil, and natural gas.

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.

•Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV (a consolidated VIE) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated VIE) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 50 percent equity-method investment in Blue Racer, and Appalachia Midstream Investments.

•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.

46

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.

Dividends

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

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

Our strategy is to provide a large-scale, reliable, and clean energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. We accomplish this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. We continue to maintain a strong commitment to safety, environmental stewardship including seeking opportunities for renewable energy ventures, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe, reliable, clean energy services to our customers and an attractive return to our shareholders. Our business plan for 2023 includes a continued focus on earnings and cash flow growth.

47

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

Potential risks and obstacles that could impact the execution of our plan include:

•A global recession, which could result in downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;

•Opposition to, and regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;

•Counterparty credit and performance risk;

•Unexpected significant increases in capital expenditures or delays in capital project execution, including increases from inflation or delays caused by supply chain disruptions;

•Unexpected changes in customer drilling and production activities, which could negatively impact gathering and processing volumes;

•Lower than anticipated demand for natural gas and natural gas products which could result in lower-than-expected volumes, energy commodity prices, and margins;

•General economic, financial markets, or industry downturns, including increased inflation and interest rates;

•Physical damages to facilities, including damage to offshore facilities by weather-related events;

•Other risks set forth under Part I, Item 1A. Risk Factors in this report.

Expansion Projects

Our ongoing major expansion projects include the following:

Transmission & Gulf of Mexico

Deepwater Shenandoah Project

In June 2021, we reached an agreement with two third-parties to provide offshore natural gas gathering and transportation services as well as onshore natural gas processing services. The project expands our existing Gulf of Mexico offshore infrastructure via a 5-mile offshore lateral pipeline from the Shenandoah platform to Discovery’s existing Keathley Canyon Connector pipeline, adds onshore processing facilities at Larose, Louisiana to handle the expected rich Shenandoah production, and the natural gas liquids will be fractionated and marketed at Discovery’s Paradis plant in Louisiana. We plan to place the project into service in the fourth quarter of 2024.

48

Deepwater Whale Project

In August 2021, we reached an agreement with two third-parties to provide offshore natural gas gathering and crude oil transportation services as well as onshore natural gas processing services. The project expands our existing Western Gulf of Mexico offshore infrastructure via a 26-mile gas lateral pipeline from the Whale platform to the existing Perdido gas pipeline and adds a new 125-mile oil pipeline from the Whale platform to our existing junction platform. We plan to place the project into service in the fourth quarter of 2024.

Regional Energy Access

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

West

Louisiana Energy Gateway

In June 2022, we announced our intention to construct new natural gas gathering assets which are expected to gather 1.8 Bcf/d of natural gas produced in the Haynesville Shale basin for delivery to premium markets, including Transco, industrial markets, and growing LNG export demand along the Gulf Coast. This project is expected to go into service in the fourth quarter of 2024.

49

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

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions. We believe that the nature of these estimates and assumptions is material due to the subjectivity and judgment necessary, or the susceptibility of such matters to change, and the impact of these on our financial condition or results of operations.

Pension and Postretirement Obligations

We have pension and other postretirement benefit plans that require the use of assumptions and estimates to determine the benefit obligations and costs. These estimates and assumptions involve significant judgement and actual results will likely be different than anticipated. Estimates and assumptions utilized include the expected long-term rates of return on plan assets, discount rates, cash balance interest crediting rate, and employee demographics, including retirement age and mortality. These assumptions are reviewed annually and adjustments are made as needed. The assumptions utilized to compute the benefit obligations and costs are shown in Note 7 – Employee Benefit Plans of Notes to Consolidated Financial Statements.

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

	Benefit Cost				Benefit Obligation
	One- Percentage- Point Increase		One- Percentage- Point Decrease		One- Percentage- Point Increase		One- Percentage- Point Decrease
	(Millions)
Pension benefits:
Discount rate	$	(21)	$	(1)	$	(69)	$	80
Expected long-term rate of return on plan assets	(11)		11		—		—
Cash balance interest crediting rate	5		(25)		50		(43)
Other postretirement benefits:
Discount rate	(3)		2		(14)		16
Expected long-term rate of return on plan assets	(2)		2		—		—

Our expected long-term rates of return on plan assets, as determined at the beginning of each fiscal year, are based on historical returns, forward-looking capital market expectations of at least 10 years from our third-party independent investment advisor, as well as the investment strategy and relative weightings of the asset classes within the investment portfolio. Our expected long-term rate of return on plan assets used for our pension plans was 3.81 percent in 2022. 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. The expected rates of return on plan assets are long-term in nature and are not significantly impacted by short-term market performance.

The discount rates for our pension and other postretirement benefit plans are determined separately based on an approach specific to our plans, which considers a yield curve of high-quality corporate bonds and the duration of the expected benefit cash flows of each plan.

50

The cash balance interest crediting rate assumption represents the average long-term rate by which the pension plans’ cash balance accounts are expected to grow. Interest on the cash balance accounts is based on the 30-year U.S. Treasury securities rate.

51

Results of Operations

Consolidated Overview

The following table and discussion is a summary of our consolidated results of operations for the three years ended December 31, 2022. The results of operations by segment are discussed in further detail following this consolidated overview discussion.

	Year Ended December 31,
	2022		$ Change from 2021*	% Change from 2021*		2021		$ Change from 2020*	% Change from 2020*		2020
	(Millions)
Revenues:
Service revenues	$	6,536	+535	+9	%	$	6,001	+77	+1	%	$	5,924
Service revenues – commodity consideration	260		+22	+9	%	238		+109	+84	%	129
Product sales	4,556		+20	—	%	4,536		+2,865	+171	%	1,671
Net gain (loss) on commodity derivatives	(387)		-239	-161	%	(148)		-143	NM		(5)
Total revenues	10,965					10,627					7,719
Costs and expenses:
Product costs	3,369		+562	+14	%	3,931		-2,386	-154	%	1,545
Net processing commodity expenses	88		+13	+13	%	101		-33	-49	%	68
Operating and maintenance expenses	1,817		-269	-17	%	1,548		-222	-17	%	1,326
Depreciation and amortization expenses	2,009		-167	-9	%	1,842		-121	-7	%	1,721
Selling, general, and administrative expenses	636		-78	-14	%	558		-92	-20	%	466
Impairment of certain assets	—		+2	+100	%	2		+180	+99	%	182
Impairment of goodwill	—		—	—	%	—		+187	+100	%	187
Other (income) expense – net	28		-14	-100	%	14		+8	+36	%	22
Total costs and expenses	7,947					7,996					5,517
Operating income (loss)	3,018					2,631					2,202
Equity earnings (losses)	637		+29	+5	%	608		+280	+85	%	328
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	18		+12	+200	%	6		+49	NM		(43)
Income (loss) before income taxes	2,542					2,073					277
Less: Provision (benefit) for income taxes	425		+86	+17	%	511		-432	NM		79
Net income (loss)	2,117					1,562					198
Less: Net income (loss) attributable to noncontrolling interests	68		-23	-51	%	45		-58	NM		(13)
Net income (loss) attributable to The Williams Companies, Inc.	$	2,049	+532	+35	%	$	1,517	+1,306	NM		$	211

_______

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

2022 vs. 2021

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,

52

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.

53

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.

2021 vs. 2020

Service revenues increased primarily due to higher transportation fee revenues associated with expansion projects placed in service at Transco in 2020 and 2021, higher revenue associated with reimbursable electricity expenses, and higher processing and fractionation revenues in our Northeast G&P segment. This increase was partially offset by lower volume deficiency fee revenues, lower gathering volumes, and lower deferred revenue amortization.

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

Product sales increased primarily due to higher prices and volumes associated with our natural gas and NGL marketing activities, as well as the inclusion of our recently acquired upstream operations. This increase also includes higher prices related to our equity NGL sales activities. These increases were partially offset by negative product marketing sales from operations acquired in the Sequent Acquisition in 2021 (which does not reflect commodity derivative net realized gains discussed below).

Net gain (loss) on commodity derivatives includes realized and unrealized gains and losses from derivative instruments. The unfavorable change primarily reflects net unrealized losses in our Gas & NGL Marketing Services segment, and net realized losses related to derivative contracts in our West and Other segments. Net realized gains at our Gas & NGL Marketing Services segment partially offset these impacts.

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

54

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

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

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

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

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

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

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

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

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

Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income. See Note 6 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.

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

Year-Over-Year Operating Results – Segments

We evaluate segment operating performance based upon Modified EBITDA. Note 18 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.

55

Transmission & Gulf of Mexico

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Service revenues	$	3,579	$	3,385	$	3,257
Service revenues – commodity consideration (1)	64		52		21
Product sales (1)	404		349		191
Segment revenues	4,047		3,786		3,469
Product costs (1)	(399)		(349)		(193)
Net processing commodity expenses (1)	(26)		(17)		(7)
Other segment costs and expenses	(1,141)		(980)		(886)
Impairment of certain assets	—		(2)		(170)
Proportional Modified EBITDA of equity-method investments	193		183		166
Transmission & Gulf of Mexico Modified EBITDA	$	2,674	$	2,621	$	2,379
Commodity margins	$	43	$	35	$	12

_______________

(1)Included as a component of Commodity margins.

2022 vs. 2021

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;

56

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.

2021 vs. 2020

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

Service revenues increased primarily due to:

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

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

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

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

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

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

Other segment costs and expenses increased primarily due to higher incentive and benefit employee-related costs as previously discussed; higher operating costs, including higher reimbursable electric power costs; and a cash out surcharge reserve, which are offset by similar changes in electricity and cash out reimbursements, reflected in Service revenues; and higher operating taxes, partially offset by a favorable change associated with the deferral of asset retirement obligation-related depreciation at Transco.

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

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

57

Northeast G&P

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Service revenues	$	1,654	$	1,528	$	1,465
Service revenues – commodity consideration (1)	14		7		7
Product sales (1)	134		99		57
Segment revenues	1,802		1,634		1,529
Product costs (1)	(135)		(99)		(57)
Net processing commodity expenses (1)	(3)		(2)		(3)
Other segment costs and expenses	(522)		(503)		(441)
Impairment of certain assets	—		—		(12)
Proportional Modified EBITDA of equity-method investments	654		682		473
Northeast G&P Modified EBITDA	$	1,796	$	1,712	$	1,489
Commodity margins	$	10	$	5	$	4

(1)Included as a component of Commodity margins.

2022 vs. 2021

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.

58

2021 vs. 2020

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

Service revenues increased primarily due to:

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

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

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

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

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

Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments primarily driven by higher volumes as well as the absence of our $26 million share of an impairment of certain assets in 2020 that were subsequently sold. Additionally, there was an increase at Blue Racer primarily due to the favorable impact of increased ownership as well as the absence of our $10 million share of an impairment of certain assets in 2020. There was also an increase at Laurel Mountain due to higher commodity-based gathering rates as well as the absence of our $11 million share of an impairment of certain assets in 2020 that were subsequently sold and higher MVC revenue, partially offset by lower volumes, and an increase at Aux Sable.

59

West

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Service revenues	$	1,542	$	1,248	$	1,272
Service revenues – commodity consideration (1)	182		179		101
Product sales (1)	841		643		152
Net realized gain (loss) on commodity derivatives – service revenues	(1)		(15)		—
Net realized gain (loss) on commodity derivatives – product sales (1)	(3)		(29)		(2)
Net realized gain (loss) on commodity derivatives	(4)		(44)		(2)
Segment revenues	2,561		2,026		1,523
Product costs (1)	(813)		(608)		(154)
Net processing commodity expenses (1)	(105)		(85)		(58)
Other segment costs and expenses	(564)		(477)		(474)
Proportional Modified EBITDA of equity-method investments	132		105		110
West Modified EBITDA	$	1,211	$	961	$	947
Commodity margins	$	102	$	100	$	39

________________

(1) Included as a component of Commodity margins.

2022 vs. 2021

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

60

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.

2021 vs. 2020

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

Service revenues decreased primarily due to:

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

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

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

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

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

Marketing margins increased by $36 million primarily due to favorable changes in net realized natural gas and NGL prices, including the impact of Winter Storm Uri in the first quarter of 2021. Product margins from our equity NGLs increased by $13 million, primarily due to favorable net realized commodity price changes, partially offset by lower sales volumes. Margins on other sales of products increased $12 million primarily due to higher commodity prices.

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

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

61

Gas & NGL Marketing Services

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Service revenues	$	3	$	3	$	32
Product sales (1)	3,534		4,292		1,602
Net realized gain (loss) from derivative instruments (1)	17		25		(3)
Net unrealized gain (loss) from derivative instruments	(321)		(109)		—
Net gain (loss) on commodity derivatives	(304)		(84)		(3)
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)
Gas & NGL Marketing Services Modified EBITDA	$	(40)	$	22	$	51
Commodity margins	$	323	$	165	$	30

________________

(1) Included as a component of Commodity margins.

2022 vs. 2021

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.

62

2021 vs. 2020

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

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

Commodity margins increased $135 million primarily due to:

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

•A $23 million increase associated with the operations acquired in the Sequent Acquisition in 2021 including $35 million primarily related to favorable pricing spreads on transportation capacity reflecting losses on physical transaction settlements more than offset by net realized gains on derivatives. The transportation related margin was partially offset by a $12 million unfavorable margin related to storage activity. The unfavorable storage margin reflects gains on physical transaction settlements offset by an $18 million charge related to the partial recognition of a purchase accounting inventory fair value adjustment which increased the weighted-average cost of inventory and $13 million related to a lower of cost or net realizable value inventory adjustment.

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

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

Other

	Year Ended December 31,
	2022		2021		2020
	(Millions)
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.

63

2022 vs. 2021

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.

2021 vs. 2020

Other Modified EBITDA increased primarily due to:

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

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

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

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

64

Management’s Discussion and Analysis of Financial Condition and Liquidity

Overview

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.

Outlook

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. Growth capital spending in 2023 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, projects supporting the Northeast G&P business and projects supporting growth in the Haynesville basin, including the Louisiana Energy Gateway project. We also expect to invest capital in the development of our upstream oil and gas properties. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that reduce emissions, meet legal, regulatory, and/or contractual commitments. We intend to fund substantially all planned 2023 capital spending with cash available after paying dividends. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities including the repurchase of our common stock.

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.

Liquidity

Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2023. Our potential material internal and external sources and uses of liquidity are as follows:

Sources:
	Cash and cash equivalents on hand
	Cash generated from operations
	Distributions from our equity-method investees
	Utilization of our credit facility and/or commercial paper program
	Cash proceeds from issuance of debt and/or equity securities
	Proceeds from asset monetizations
Uses:
	Working capital requirements
	Capital and investment expenditures
	Product costs
	Gas & NGL Marketing Services payments for transportation and storage capacity and gas supply
	Other operating costs including human capital expenses
	Quarterly dividends to our shareholders
	Repayments of borrowings under our credit facility and/or commercial paper program
	Debt service payments, including payments of long-term debt
	Distributions to noncontrolling interests
	Share repurchase program

65

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.

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:

Available Liquidity	December 31, 2022
	(Millions)
Cash and cash equivalents	$	152
Capacity available under our $3.75 billion credit facility, less amounts outstanding under our $3.5 billion commercial paper program (1)	3,400
	$	3,552

__________

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

Dividends

We increased our regular quarterly cash dividend to common stockholders by approximately 3.7 percent from the $0.41 per share paid in each quarter of 2021, to $0.425 per share paid in each quarter of 2022.

Registrations

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

Distributions from Equity-Method Investees

The organizational documents of entities in which we have an equity-method investment generally require periodic distributions of their available cash to their members. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses. See Note 8 – Investing Activities of Notes to Consolidated Financial Statements for our more significant equity-method investees.

Credit Ratings

The interest rates at which we are able to borrow money are impacted by our credit ratings. The current ratings are as follows:

Rating Agency	Outlook	Senior Unsecured Debt Rating
S&P Global Ratings	Stable	BBB
Moody’s Investors Service	Stable	Baa2
Fitch Ratings	Stable	BBB

These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our securities, and each rating should be evaluated independently of any other rating. No assurance can be given that

66

the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current criteria for investment-grade ratios. A downgrade of our credit ratings might increase our future cost of borrowing and, if ratings were to fall below investment-grade, could require us to provide additional collateral to third parties, negatively impacting our available liquidity.

Sources (Uses) of Cash

The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table):

	Cash Flow	Year Ended December 31,
	Category	2022		2021		2020
		(Millions)
Sources of cash and cash equivalents:
Operating activities – net	Operating	$	4,889	$	3,945	$	3,496
Proceeds from long-term debt (see Note 12)	Financing	1,755		2,155		2,199
Proceeds from credit-facility borrowings	Financing	—		—		1,700
Proceeds from commercial paper - net	Financing	345		—		—
Contributions in aid of construction	Investing	12		52		37
Uses of cash and cash equivalents:
Payments of long-term debt (see Note 12)	Financing	(2,876)		(894)		(2,141)
Common dividends paid	Financing	(2,071)		(1,992)		(1,941)
Payments on credit-facility borrowings	Financing	—		—		(1,700)
Capital expenditures	Investing	(2,253)		(1,239)		(1,239)
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 and contributions to equity-method investments (see Note 8)	Investing	(166)		(115)		(325)
Other sources / (uses) – net	Financing and Investing	(26)		(36)		(48)
Increase (decrease) in cash and cash equivalents		$	(1,528)	$	1,538	$	(147)

Operating activities

The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation and amortization, Provision (benefit) for deferred income taxes, Equity (earnings) losses, Impairment of goodwill, Impairment of equity-method investments, Impairment of certain assets, Net unrealized (gain) loss from derivative instruments, and Inventory write-downs.

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.

67

Environmental

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own (see Note 17 – Contingent Liabilities and Commitments of Notes to Consolidated Financial Statements). We are monitoring these sites in a coordinated effort with other potentially responsible parties, the EPA, or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. 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. During 2022, we paid approximately $5 million for cleanup and/or remediation and monitoring activities. We expect to pay approximately $11 million in 2023 for these activities. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At December 31, 2022, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

The EPA and various state regulatory agencies routinely propose and promulgate new rules and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine maximum achievable control technology, reviews and updates to the National Ambient Air Quality Standards, and rules for new and existing source performance standards for volatile organic compounds and methane. We continuously monitor these regulatory changes and how they may impact our operations. Implementation of new or modified regulations may result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new and existing facilities in affected areas; 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 transmission pipelines. 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.

68

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

Our current interest rate risk exposure is related primarily to our debt portfolio. Our debt portfolio is primarily comprised of fixed rate debt, which mitigates the impact of fluctuations in interest rates. Any borrowings under our credit facility and any issuances under our commercial paper program could be at a variable interest rate and could expose us to the risk of increasing interest rates. The maturity of our long-term debt portfolio is partially influenced by the expected lives of our operating assets. (See Note 12 – Debt and Banking Arrangements of Notes to Consolidated Financial Statements.)

The tables below provide information by maturity date about our interest rate risk-sensitive instruments as of December 31, 2022 and 2021. See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements for the methods used in determining the fair value of our long-term debt.

		2023			2024			2025			2026			2027			Thereafter (1)			Total		Fair Value December 31, 2022
	(Millions)
Long-term debt, including current portion:
Fixed rate		$	629		$	2,281		$	1,619		$	1,245		$	1,993		$	14,787		$	22,554	$	21,569
Weighted-average interest rate		5.0		%	5.0		%	5.1		%	5.0		%	5.0		%	5.1		%
Commercial paper (2)		$	350		$	—		$	—		$	—		$	—		$	—		$	350	$	350
		2022			2023			2024			2025			2026			Thereafter (1)			Total		Fair Value December 31, 2021
	(Millions)
Long-term debt, including current portion:
Fixed rate		$	2,026		$	1,478		$	2,281		$	1,619		$	1,244		$	15,027		$	23,675	$	27,768
Weighted-average interest rate		4.9		%	5.0		%	5.1		%	5.1		%	5.1		%	5.1		%

__________________

(1)    Includes unamortized discount / premium and debt issuance costs.

(2) The weighted-average interest rate for commercial paper was 4.8 percent as of December 31, 2022.

Commodity Price Risk

We are exposed to commodity price risk through our natural gas and NGL marketing activities, including contracts to purchase, sell, transport, and store product. We routinely manage this risk with a variety of exchange-traded and OTC energy contracts such as forward contracts, futures contracts, and basis swaps, as well as physical transactions. Although many of the contracts used to manage commodity exposure are derivative instruments, these economic hedges are not designated or do not qualify for hedge accounting treatment.

We are also exposed to commodity prices through our upstream business and certain gathering and processing contracts. We use derivative instruments to lock in forward sales prices on a portion of our expected future production. These economic hedges are not designated for hedge accounting treatment.

69

The maturities of our derivative contracts at December 31, 2022, as well as the maturities of the derivative contracts related to the operations acquired in the Sequent Acquisition at December 31, 2021, were as follows:

	Total Fair Value		Maturity
Fair Value Measurements Using (1)			2023		2024 - 2025		2026 - 2027+
	(Millions)
Level 1 (2)	$	(2)	$	11	$	(9)	$	(4)
Level 2	(586)		(171)		(224)		(191)
Level 3	(56)		(19)		2		(39)
Fair value of contracts outstanding at December 31, 2022	$	(644)	$	(179)	$	(231)	$	(234)

	Total Fair Value		Maturity
Fair Value Measurements Using (1)			2022		2023 - 2024		2025 - 2026+
	(Millions)
Level 1 (3)	$	(69)	$	(49)	$	(30)	$	10
Level 2	(317)		(77)		(108)		(132)
Level 3	(16)		(13)		(11)		8
Fair value of contracts outstanding at December 31, 2021	$	(402)	$	(139)	$	(149)	$	(114)

_______________

(1)See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk of Notes to Consolidated Financial Statements for discussion of valuation techniques by level within the fair value hierarchy. See Note 16 – Derivatives of Notes to Consolidated Financial Statements for the amount of change in fair value recognized in our Consolidated Statement of Income.

(2)Net commodity derivative assets and liabilities exclude $202 million of net cash collateral in Level 1.

(3)Net commodity derivative assets and liabilities related to the operations acquired in the Sequent Acquisition exclude $267 million of net cash collateral in Level 1.

Value at Risk (VaR)

VaR is the maximum predicted loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability. Our VaR may not be comparable to that of other companies due to differences in the factors used to calculate VaR. Our VaR is determined using parametric models with 95 percent confidence intervals and one-day holding periods, which means that 95 percent of the time, the risk of loss in a day from a portfolio of positions is expected to be less than or equal to the amount of VaR calculated. Our open exposure is managed in accordance with established policies that limit market risk and require daily reporting of predicted financial loss to management. Because we generally manage physical gas assets and economically protect our positions by hedging in the futures markets, our open exposure is generally mitigated. We employ daily risk testing, using both VaR and stress testing, to evaluate the risk of our positions.

We actively monitor open commodity marketing positions and the resulting VaR and maintain a relatively small risk exposure as total buy volume is close to sell volume, with minimal open natural gas price risk. Starting in the second quarter of 2022, following the further integration of our legacy trading activities with the operations acquired in the Sequent Acquisition, we now present VaR for our integrated natural gas trading operations. For the second half of 2021 and the first quarter of 2022, the VaR presented reflects the legacy Sequent operations only.

70

At December 31, 2022, the VaR associated with this activity was $10 million. We had the following VaRs for the periods shown:

	Nine Months Ended  December 31, 2022		Three Months Ended  March 31, 2022		Six Months Ended December 31, 2021
	Trading		Sequent Only		Sequent Only
	(Millions)
Average	$	10	$	6	$	4
High	$	39	$	10	$	7
Low	$	4	$	4	$	2

Our non-trading portfolio primarily consists of derivatives that hedge our upstream business and certain gathering and processing contracts. At December 31, 2022, the VaR associated with these derivatives was $8 million.

71

Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Stockholders and the Board of Directors of

The Williams Companies, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheet of The Williams Companies, Inc. (the Company) as of December 31, 2022 and 2021, the related consolidated statements of income, comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2022, and the related notes and the financial statement schedule listed in the index at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, based on our audits and the report of other auditors, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2022 and 2021, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with U.S. generally accepted accounting principles.

We did not audit the 2020 financial statements of Gulfstream Natural Gas System, L.L.C. (Gulfstream), a limited liability corporation in which the Company has a 50 percent interest. In the consolidated financial statements, the Company’s investment in Gulfstream was $204 million as of December 31, 2020, and the Company’s equity earnings in the net income of Gulfstream were $77 million in 2020. Those financial statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Gulfstream for 2020, is based solely on the report of other auditors.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 27, 2023 expressed an unqualified opinion thereon.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.

72

Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the account or disclosure to which it relates.
	Pension and Other Postretirement Benefit Obligations
Description of the Matter	At December 31, 2022, the Company’s aggregate pension and other postretirement benefit obligations were $1,092 million and were exceeded by the fair value of pension and other postretirement plan assets of $1,370 million, resulting in overfunded pension and other postretirement benefit obligations of $278 million. As explained in Note 7 to the consolidated financial statements, the Company utilized key assumptions to determine the pension and other postretirement benefit obligations. Auditing the pension and other postretirement benefit obligations is complex and required the involvement of specialists due to the judgmental nature of the actuarial assumptions (e.g., discount rates and cash balance interest crediting rate) used in the measurement process. These assumptions have a significant effect on the projected benefit obligations.
How We Addressed the Matter in Our Audit	We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls relating to the measurement and valuation of the pension and other postretirement benefit obligations, including controls over management’s review of the pension and other postretirement obligations, the significant actuarial assumptions, and the data inputs. To test the pension and other postretirement benefit obligations, our audit procedures included, among others, evaluating the methodologies used, the significant actuarial assumptions discussed above, and the underlying data used by the Company. We compared the actuarial assumptions used by management to historical trends and evaluated the changes in the funded status from prior year. In addition, we involved our actuarial specialists to assist with our procedures. For example, we evaluated management’s methodology for determining the discount rates that reflect the maturity and duration of the benefit payments and are used to measure the pension and other postretirement benefit obligations. As part of this assessment, we independently developed a range of yield curves, we compared the projected cash flows to prior year, and compared the current year benefits paid to the prior year projected cash flows. To test the cash balance interest crediting rate, we independently calculated a range of rates and compared them to the rate used by management. We also tested the completeness and accuracy of the underlying data, including the participant data.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 1962.

Tulsa, Oklahoma

February 27, 2023

73

Report of Independent Registered Public Accounting Firm

To the Management Committee and Members of Gulfstream Natural Gas System, L.L.C.:

Opinion on the Financial Statements

We have audited the statements of earnings, comprehensive income, changes in members’ equity and cash flows of Gulfstream Natural Gas System, L.L.C. (the “Company”) for the year ended December 31, 2020, including the related notes (collectively referred to as the “financial statements”) (not presented herein). In our opinion, the financial statements present fairly, in all material respects, the results of operations and cash flows of the Company for the year ended December 31, 2020 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit of these financial statements in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud.

Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 27, 2023

We have served as the Company’s auditor since 2018.

74

The Williams Companies, Inc.

Consolidated Statement of Income

		Year Ended December 31,
		2022		2021		2020
	(Millions, except per-share amounts)
Revenues:
Service revenues		$	6,536	$	6,001	$	5,924
Service revenues – commodity consideration		260		238		129
Product sales		4,556		4,536		1,671
Net gain (loss) on commodity derivatives		(387)		(148)		(5)
Total revenues		10,965		10,627		7,719
Costs and expenses:
Product costs		3,369		3,931		1,545
Net processing commodity expenses		88		101		68
Operating and maintenance expenses		1,817		1,548		1,326
Depreciation and amortization expenses		2,009		1,842		1,721
Selling, general, and administrative expenses		636		558		466
Impairment of certain assets (Note 15)		—		2		182
Impairment of goodwill (Note 15)		—		—		187
Other (income) expense – net		28		14		22
Total costs and expenses		7,947		7,996		5,517
Operating income (loss)		3,018		2,631		2,202
Equity earnings (losses) (Note 8)		637		608		328
Impairment of equity-method investments (Note 15)		—		—		(1,046)
Other investing income (loss) – net		16		7		8
Interest incurred		(1,167)		(1,190)		(1,192)
Interest capitalized		20		11		20
Other income (expense) – net		18		6		(43)
Income (loss) before income taxes		2,542		2,073		277
Less: Provision (benefit) for income taxes		425		511		79
Net income (loss)		2,117		1,562		198
Less: Net income (loss) attributable to noncontrolling interests		68		45		(13)
Net income (loss) attributable to The Williams Companies, Inc.		2,049		1,517		211
Less: Preferred stock dividends		3		3		3
Net income (loss) available to common stockholders		$	2,046	$	1,514	$	208
Basic earnings (loss) per common share:
Net income (loss) available to common stockholders		$	1.68	$	1.25	$	.17
Weighted-average shares (thousands)		1,218,362		1,215,221		1,213,631
Diluted earnings (loss) per common share:
Net income (loss) available to common stockholders		$	1.67	$	1.24	$	.17
Weighted-average shares (thousands)		1,222,672		1,218,215		1,215,165

See accompanying notes.

75

The Williams Companies, Inc.

Consolidated Statement of Comprehensive Income (Loss)

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Net income (loss)	$	2,117	$	1,562	$	198
Other comprehensive income (loss):
Designated cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $1, $14, and $— in 2022, 2021, and 2020, respectively	(3)		(40)		(2)
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $—, ($14), and $— in 2022, 2021, and 2020, respectively	—		41		1
Pension and other postretirement benefits:
Net actuarial gain (loss) arising during the year, net of taxes of $1, ($18), and ($27) in 2022, 2021, and 2020, respectively	1		51		81
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($4), ($4), and ($7) in 2022, 2021, and 2020, respectively	11		11		23
Other comprehensive income (loss)	9		63		103
Comprehensive income (loss)	2,126		1,625		301
Less: Comprehensive income (loss) attributable to noncontrolling interests	68		45		(13)
Comprehensive income (loss) attributable to The Williams Companies, Inc.	$	2,058	$	1,580	$	314

See accompanying notes.

76

The Williams Companies, Inc.

Consolidated Balance Sheet

	December 31,
	2022		2021
	(Millions, except per-share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	152	$	1,680
Trade accounts and other receivables	2,729		1,986
Allowance for doubtful accounts	(6)		(8)
Trade accounts and other receivables – net	2,723		1,978
Inventories	320		379
Derivative assets	323		301
Other current assets and deferred charges	279		211
Total current assets	3,797		4,549
Investments	5,065		5,127
Property, plant, and equipment – net	30,889		29,258
Intangible assets – net of accumulated amortization	7,363		7,402
Regulatory assets, deferred charges, and other	1,319		1,276
Total assets	$	48,433	$	47,612
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	2,327	$	1,746
Derivative liabilities	316		166
Accrued and other current liabilities	1,270		1,035
Commercial paper	350		—
Long-term debt due within one year	627		2,025
Total current liabilities	4,890		4,972
Long-term debt	21,927		21,650
Deferred income tax liabilities	2,887		2,453
Regulatory liabilities, deferred income, and other	4,684		4,436
Contingent liabilities and commitments (Note 17)
Equity:
Stockholders’ equity:
Preferred stock ($1 par value; 30 million shares authorized at December 31, 2022 and December 31, 2021; 35,000 shares issued at December 31, 2022 and December 31, 2021)	35		35
Common stock ($1 par value; 1,470 million shares authorized at December 31, 2022 and December 31, 2021; 1,253 million shares issued at December 31, 2022 and 1,250 million shares issued at December 31, 2021)	1,253		1,250
Capital in excess of par value	24,542		24,449
Retained deficit	(13,271)		(13,237)
Accumulated other comprehensive income (loss)	(24)		(33)
Treasury stock, at cost (35 million shares of common stock)	(1,050)		(1,041)
Total stockholders’ equity	11,485		11,423
Noncontrolling interests in consolidated subsidiaries	2,560		2,678
Total equity	14,045		14,101
Total liabilities and equity	$	48,433	$	47,612

See accompanying notes.

77

The Williams Companies, Inc.

Consolidated Statement of Changes in Equity

	The Williams Companies, Inc. Stockholders
	Preferred Stock		Common Stock		Capital in Excess of Par Value		Retained Deficit		AOCI*		Treasury Stock		Total Stockholders’ Equity		Noncontrolling Interests		Total Equity
	(Millions)
Balance at December 31, 2019	$	35	$	1,247	$	24,323	$	(11,002)	$	(199)	$	(1,041)	$	13,363	$	3,001	$	16,364
Net income (loss)	—		—		—		211		—		—		211		(13)		198
Other comprehensive income (loss)	—		—		—		—		103		—		103		—		103
Cash dividends – common stock ($1.60 per share)	—		—		—		(1,941)		—		—		(1,941)		—		(1,941)
Dividends and distributions to noncontrolling interests	—		—		—		—		—		—		—		(185)		(185)
Stock-based compensation and related common stock issuances, net of tax	—		1		50		—		—		—		51		—		51
Contributions from noncontrolling interests	—		—		—		—		—		—		—		7		7
Other	—		—		(2)		(16)		—		—		(18)		4		(14)
Net increase (decrease) in equity	—		1		48		(1,746)		103		—		(1,594)		(187)		(1,781)
Balance at December 31, 2020	35		1,248		24,371		(12,748)		(96)		(1,041)		11,769		2,814		14,583
Net income (loss)	—		—		—		1,517		—		—		1,517		45		1,562
Other comprehensive income (loss)	—		—		—		—		63		—		63		—		63
Cash dividends – common stock ($1.64 per share)	—		—		—		(1,992)		—		—		(1,992)		—		(1,992)
Dividends and distributions to noncontrolling interests	—		—		—		—		—		—		—		(187)		(187)
Stock-based compensation and related common stock issuances, net of tax	—		2		78		—		—		—		80		—		80
Purchase of partial interest in consolidated subsidiary (Note 8)	—		—		—		—		—		—		—		(3)		(3)
Contributions from noncontrolling interests	—		—		—		—		—		—		—		9		9
Other	—		—		—		(14)		—		—		(14)		—		(14)
Net increase (decrease) in equity	—		2		78		(489)		63		—		(346)		(136)		(482)
Balance at December 31, 2021	35		1,250		24,449		(13,237)		(33)		(1,041)		11,423		2,678		14,101
Net income (loss)	—		—		—		2,049		—		—		2,049		68		2,117
Other comprehensive income (loss)	—		—		—		—		9		—		9		—		9
Cash dividends – common stock ($1.70 per share)	—		—		—		(2,071)		—		—		(2,071)		—		(2,071)
Dividends and distributions to noncontrolling interests	—		—		—		—		—		—		—		(204)		(204)
Stock-based compensation and related common stock issuances, net of tax	—		3		93		—		—		—		96		—		96
Contributions from noncontrolling interests	—		—		—		—		—		—		—		18		18
Purchase of treasury stock	—		—		—		—		—		(9)		(9)		—		(9)
Other	—		—		—		(12)		—		—		(12)		—		(12)
Net increase (decrease) in equity	—		3		93		(34)		9		(9)		62		(118)		(56)
Balance at December 31, 2022	$	35	$	1,253	$	24,542	$	(13,271)	$	(24)	$	(1,050)	$	11,485	$	2,560	$	14,045

*Accumulated Other Comprehensive Income (Loss)

See accompanying notes.

78

The Williams Companies, Inc.

Consolidated Statement of Cash Flows

	Year Ended December 31,
	2022		2021		2020
	(Millions)
OPERATING ACTIVITIES:
Net income (loss)	$	2,117	$	1,562	$	198
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	2,009		1,842		1,721
Provision (benefit) for deferred income taxes	431		509		108
Equity (earnings) losses	(637)		(608)		(328)
Distributions from equity-method investees (Note 8)	865		757		653
Impairment of goodwill (Note 15)	—		—		187
Impairment of equity-method investments (Note 15)	—		—		1,046
Impairment of certain assets (Note 15)	—		2		182
Net unrealized (gain) loss from derivative instruments	249		109		—
Inventory write-downs	161		15		17
Amortization of stock-based awards	73		81		52
Cash provided (used) by changes in current assets and liabilities:
Accounts receivable	(733)		(545)		(2)
Inventories	(110)		(139)		(28)
Other current assets and deferred charges	(33)		(63)		11
Accounts payable	410		643		(7)
Accrued and other current liabilities	209		58		(309)
Changes in current and noncurrent derivative assets and liabilities	94		(277)		(4)
Other, including changes in noncurrent assets and liabilities	(216)		(1)		(1)
Net cash provided (used) by operating activities	4,889		3,945		3,496
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	345		—		—
Proceeds from long-term debt	1,755		2,155		3,899
Payments of long-term debt	(2,876)		(894)		(3,841)
Proceeds from issuance of common stock	54		9		9
Common dividends paid	(2,071)		(1,992)		(1,941)
Dividends and distributions paid to noncontrolling interests	(204)		(187)		(185)
Contributions from noncontrolling interests	18		9		7
Payments for debt issuance costs	(17)		(26)		(20)
Other – net	(46)		(16)		(13)
Net cash provided (used) by financing activities	(3,042)		(942)		(2,085)
INVESTING ACTIVITIES:
Property, plant, and equipment:
Capital expenditures (1)	(2,253)		(1,239)		(1,239)
Dispositions – net	(30)		(8)		(36)
Contributions in aid of construction	12		52		37
Purchases of businesses, net of cash acquired (Note 3)	(933)		(151)		—
Purchases of and contributions to equity-method investments (Note 8)	(166)		(115)		(325)
Other – net	(5)		(4)		5
Net cash provided (used) by investing activities	(3,375)		(1,465)		(1,558)
Increase (decrease) in cash and cash equivalents	(1,528)		1,538		(147)
Cash and cash equivalents at beginning of year	1,680		142		289
Cash and cash equivalents at end of year	$	152	$	1,680	$	142
_________
(1) Increases to property, plant, and equipment	$	(2,394)	$	(1,305)	$	(1,160)
Changes in related accounts payable and accrued liabilities	141		66		(79)
Capital expenditures	$	(2,253)	$	(1,239)	$	(1,239)

See accompanying notes.

79

The Williams Companies, Inc.

Notes to Consolidated Financial Statements

Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies

General

Unless the context clearly indicates otherwise, references in this report to “Williams,” “we,” “our,” “us,” or like terms refer to The Williams Companies, Inc. and its subsidiaries. Unless the context clearly indicates otherwise, references to “Williams,” “we,” “our,” and “us” include the operations in which we own interests accounted for as equity-method investments that are not consolidated in our financial statements. When we refer to our equity investees by name, we are referring exclusively to their businesses and operations.

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 share repurchase program does not have an expiration date. There were $9 million and no repurchases under the program in 2022 and 2021, respectively.

Description of Business

We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located in the United States and are 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, as well as corporate activities are included in Other.

Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline LLC (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 LLC (Gulfstar One) (a consolidated variable interest entity, or VIE), a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), and a 60 percent equity-method investment in Discovery Producer Services LLC (Discovery). Transmission & Gulf of Mexico also includes natural gas storage facilities and pipelines providing services in north Texas.

Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in Ohio Valley Midstream LLC (Northeast JV) (a consolidated VIE) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated VIE) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 50 percent equity-method investment in Blue Racer Midstream LLC (Blue Racer), and Appalachia Midstream Services, LLC, 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 (Appalachia Midstream Investments).

West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of east Texas and northwest Louisiana, and the Mid-Continent region which includes the Anadarko and Permian basins. This segment also includes our NGL storage facilities, an undivided 50

80

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in Overland Pass Pipeline Company LLC (OPPL), a 50 percent equity-method investment in Rocky Mountain Midstream Holdings LLC (RMM), a 20 percent equity-method investment in Targa Train 7 LLC (Targa Train 7) (a nonconsolidated VIE), and a 15 percent equity-method investment in Brazos Permian II, LLC (Brazos Permian II) (a nonconsolidated VIE).

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 natural gas liquids (NGLs) on strategically positioned assets.

Basis of Presentation

Discontinued operations

Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations.

Significant risks and uncertainties

We believe that the carrying value of certain of our property, plant, and equipment and intangible assets, notably certain acquired assets accounted for as business combinations between 2012 and 2014, may be in excess of current fair value. However, the carrying value of these assets, in our judgment, continues to be recoverable. It is reasonably possible that future strategic decisions, including transactions such as monetizing assets or contributing assets to new ventures with third parties, as well as unfavorable changes in expected producer activities, could impact our assumptions and ultimately result in impairments of these assets. Such transactions or developments may also indicate that certain of our equity-method investments have experienced other-than-temporary declines in value, which could result in impairment.

Summary of Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain ventures in which we own an undivided interest. Our judgment is required to evaluate whether we control an entity. Key areas of that evaluation include:

•Determining whether an entity is a VIE (see Note 2 – Variable Interest Entities);

•Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests;

•Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether we are a VIE’s primary beneficiary;

•Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities.

We apply the equity method of accounting to investments over which we exercise significant influence but do not control. Distributions received from equity-method investees are presented in our Consolidated Statement of Cash Flows according to the nature of the distributions approach, which classifies distributions received from equity-method investees as either returns on investment (cash inflows from operating activities) or returns of

81

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

investment (cash inflows from investing activities) based on the nature of the activities of the equity-method investee that generated the distribution.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Significant estimates and assumptions include:

•Impairment assessments of investments, property, plant, and equipment, and intangible assets;

•Litigation-related contingencies;

•Environmental remediation obligations;

•Depreciation and/or amortization of long-lived assets, which are comprised of property, plant, and equipment, and intangible assets;

•Depreciation and/or amortization of equity-method investment basis differences;

•Asset retirement obligations (AROs);

•Measurement of fair value of derivatives;

•Pension and postretirement valuation variables;

•Measurement of regulatory liabilities;

•Measurement of deferred income tax assets and liabilities, including assumptions related to the realization of deferred income tax assets;

•Revenue recognition, including estimates utilized in recognition of deferred revenue;

•Purchase price accounting.

These estimates are discussed further throughout these notes.

Regulatory accounting

Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC), and their rates are established by the FERC. Therefore, we have determined that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” (ASC 980) that certain costs that would otherwise be charged to expense should be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense should be deferred as regulatory liabilities, based on the expected return to customers in future rates. Management’s expected recovery of deferred costs and return of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. We record certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refunded in future rates. Accounting for these operations that are regulated can differ from the accounting requirements for nonregulated operations. For example, for regulated operations, allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in the process of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual cost of construction under established regulatory practices; nonregulated operations are only allowed to capitalize the cost of debt funds related to construction activities, while a component for equity is prohibited. The

82

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, AROs, shipper imbalance activity, fuel and power cost differentials, depreciation, negative salvage, pension and other postretirement benefits, customer tax refunds, and rate allowances for deferred income taxes at a historically higher federal income tax rate.

Our current and noncurrent regulatory asset and liability balances at December 31, 2022 and 2021 are as follows:

	December 31,
	2022		2021
	(Millions)
Current assets reported within Other current assets and deferred charges	$	138	$	111
Noncurrent assets reported within Regulatory assets, deferred charges, and other	459		415
Total regulated assets	$	597	$	526
Current liabilities reported within Accrued and other current liabilities	$	201	$	56
Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other	1,233		1,324
Total regulated liabilities	$	1,434	$	1,380

Revenue recognition

Customers in our gas pipeline businesses are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical power generators. Customers in our midstream businesses are comprised of oil and natural gas producer counterparties. Customers for our product sales are comprised of public utilities, gas marketers, and direct industrial users.

Service revenue contracts from our gas pipeline and midstream businesses contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single performance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer.

Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. For our rate-regulated gas pipeline businesses that apply ASC 980, we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, in our judgment, the construction activities do not represent an ongoing major and central operation of our gas pipeline businesses and are not within the scope of ASC Topic 606, “Revenue from Contracts with Customers”. Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset, which are referred to as Contributions in aid of construction in our Consolidated Statement of Cash Flows. For our midstream businesses, reimbursement and service contracts with customers are viewed together as providing the same commercial objective, as we have the ability to negotiate the mix of consideration between reimbursements and amounts billed over time. Accordingly, we generally recognize reimbursements of construction costs from customers on a gross basis as a contract liability separate from the associated costs included within property, plant, and equipment. The contract liability is recognized into service revenues as the underlying performance obligations are satisfied.

Service Revenues

Gas pipeline businesses: Revenues from our regulated interstate natural gas pipeline businesses, which are subject to regulation by certain state and federal authorities, including the FERC, include both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a daily or monthly reservation charge based on the pipeline or storage capacity reserved, and a commodity charge

83

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or based on negotiated contractual rates, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one-month periods or less. Our performance obligations related to our interstate natural gas pipeline businesses include the following:

•Firm transportation or storage under firm transportation and storage contracts—an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities;

•Interruptible transportation or storage under interruptible transportation and storage contracts—an integrated package of services typically constituting a single performance obligation once scheduled, which includes receiving, transporting or storing (as applicable), and redelivering commodities.

In situations where, in our judgment, we consider the integrated package of services as a single performance obligation, which represents a majority of our interstate natural gas pipeline contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready performance obligation.

We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges in our interstate natural gas pipeline businesses are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refund upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.

Midstream businesses: Revenues from our non-regulated gathering, processing, transportation, and storage midstream businesses include contracts for natural gas gathering, processing, treating, compression, transportation, and other related services with contract terms that are generally long-term in nature and may extend up to the production life of the associated reservoir. Additionally, our midstream businesses generate revenues from fees charged for storing customers’ natural gas and NGLs, generally under prepaid contracted storage capacity contracts. In situations where, in our judgment, we provide an integrated package of services combined into a single performance obligation, which represents a majority of this class of contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to provide gathering, processing, transportation, storage, and related services resulting in the delivery, or redelivery in the context of storage services, of pipeline-quality natural gas and NGLs to the customer. As such, revenue is recognized at the daily completion of the integrated package of services as the integrated package represents a single performance obligation. Additionally, certain contracts in our midstream businesses contain fixed or upfront payment terms that result in the deferral of revenues until such services have been performed or such capacity has been made available.

We also earn revenues from offshore crude oil and natural gas gathering and transportation and offshore production handling. These services represent an integrated package of services and are considered a single distinct performance obligation for which we recognize revenues as the services are provided to the customer.

84

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

We generally earn a contractually stated fee per unit for the volume of product transported, gathered, processed, or stored. The rate is generally fixed; however, certain contracts contain variable rates that are subject to change based on commodity prices, levels of throughput, or an annual adjustment based on a formulaic cost of service calculation. In addition, we have contracts with contractually stated fees that decline over the contract term, such as declines based on the passage of time periods or achievement of cumulative throughput amounts. For all of our contracts, we allocate the transaction price to each performance obligation based on the judgmentally determined relative standalone selling price. The excess of consideration received over revenue recognized results in the deferral of those amounts until future periods based on a units of production or straight-line methodology as these methods appropriately match the consumption of services provided to the customer. The units of production methodology requires the use of production estimates that are uncertain and the use of judgment when developing estimates of future production volumes, thus impacting the rate of revenue recognition. Production estimates are monitored as circumstances and events warrant. Certain of our gas gathering and processing agreements have minimum volume commitments (MVC). If a customer under such an agreement fails to meet its MVC for a specified period (thus not exercising all the contractual rights to gathering and processing services within the specified period, herein referred to as “breakage”), it is obligated to pay a contractually determined fee based upon the shortfall between the actual gathered or processed volumes and the MVC for the period contained in the contract. When we conclude, based on management’s judgment, it is probable that the customer will not exercise all or a portion of its remaining rights, we recognize revenue associated with such breakage amount in proportion to the pattern of exercised rights within the respective MVC period.

Under keep-whole and percent-of-liquids processing contracts, we receive commodity consideration in the form of NGLs and take title to the NGLs at the tailgate of the plant. We recognize such commodity consideration as service revenue based on the market value of the NGLs retained at the time the processing is provided. The current market value, as opposed to the market value at the contract inception date, is used due to a combination of factors, including the fact that the volume, mix, and market price of NGL consideration to be received is unknown at the time of contract execution and is not specified in our contracts with customers. Additionally, product sales revenue (discussed below) is recognized upon the sale of the NGLs to a third party based on the sales price at the time of sale. As a result, revenue is recognized in our Consolidated Statement of Income both at the time the processing service is provided in Service revenues – commodity consideration and at the time the NGLs retained as part of the processing service are sold in Product sales. The recognition of revenue related to commodity consideration has the impact of increasing the book value of NGL inventory, resulting in higher cost of goods sold at the time of sale.

Product Sales

In the course of providing transportation services to customers of our gas pipeline businesses and gathering and processing services to customers of our midstream businesses, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs or gathering and processing agreements, respectively. Revenue is recognized from the sale of natural gas upon settlement of imbalances.

In certain instances, we purchase NGLs, crude oil, and natural gas from our oil and natural gas producer customers which we remarket. In addition, we retain NGLs as consideration in certain processing arrangements, as discussed above in the Service Revenues - Midstream businesses section. We also market natural gas and NGLs from the production at our upstream properties. We recognize revenue from the sale of these commodities when the products have been sold and delivered. Our product sales contracts are primarily short-term contracts based on prevailing market rates at the time of the transaction.

We purchase natural gas for storage when the current market price paid to buy and transport natural gas plus the cost to store and finance the natural gas is less than an estimated, forward market price that can be received in the future, resulting in positive net product sales. Commodity-based exchange-traded futures

85

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

contracts and over-the-counter (OTC) contracts are used to sell natural gas at that future price to substantially protect the natural gas revenues that will ultimately be realized when the stored natural gas is sold. Additionally, we enter into transactions to secure transportation capacity between delivery points in order to serve our customers and various markets.

The physical purchase, transportation, storage, and sale of natural gas are accounted for on a weighted-average cost or accrual basis, as appropriate, unlike the fair value basis utilized for the derivatives used to mitigate the natural gas price risk associated with the storage and transportation portfolio. Monthly demand charges are incurred for the contracted storage and transportation capacity and payments associated with asset management agreements, and these demand charges and payments are recognized in our Consolidated Statement of Income in the period they are incurred.

As we are acting as an agent for our natural gas marketing customers and engage in energy trading activities, our natural gas marketing revenues are presented net of the related costs of those activities. Prior to the 2022 integration of our legacy gas marketing operations with the acquired Sequent Acquisition operations (see Note 3 – Acquisitions), our legacy gas marketing operations were reported on a gross basis.

Contract Assets

Our contract assets primarily consist of revenue recognized under contracts containing MVC features whereby management has concluded it is probable there will be a short-fall payment at the end of the current MVC period, which typically follows the calendar year, and that a significant reversal of revenue recognized currently for the future MVC payment will not occur. As a result, our contract assets related to our future MVC payments are generally expected to be collected within the next 12 months and are included within Other current assets and deferred charges in our Consolidated Balance Sheet until such time as the MVC short-fall payments are invoiced to the customer.

Contract Liabilities

Our contract liabilities consist of advance payments primarily from midstream business customers which include construction reimbursements, prepayments, and other billings and transactions for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily based on a units of production methodology over the remaining contractual service periods, and are classified as current or noncurrent according to when such amounts are expected to be recognized. Current and noncurrent contract liabilities are included within Accrued and other current liabilities and Regulatory liabilities, deferred income, and other, respectively, in our Consolidated Balance Sheet.

Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer, when the customer pays for those goods or services, and the prevailing interest rates. We have assessed our contracts for significant financing components and determined, in our judgment, that one group of contracts entered into in contemplation of one another for certain capital reimbursements contains a significant financing component. As a result, we recognize noncash interest expense based on the effective interest method and revenue (noncash) is recognized when the underlying asset is placed into service utilizing a units of production or straight-line methodology over the life of the corresponding customer contract.

Derivative instruments and hedging activities

We are exposed to commodity price risk. We utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of energy commodities. We purchase natural gas for storage when the current market price paid

86

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

to buy and transport natural gas plus the cost to store and finance the natural gas is less than an estimated, forward market price that can be received in the future. Additionally, we enter into transactions to secure transportation capacity between delivery points in order to serve our customers and various markets. Commodity-based exchange-traded futures contracts and OTC contracts are used to capture the price differential or spread between the locations served by the capacity in order to substantially protect the natural gas revenues that will ultimately be realized when the physical flow of natural gas between receipt and delivery points occurs. Some commodity-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the natural gas marketing operations. These contracts generally meet the definition of derivatives and are typically not designated as hedges for accounting purposes. When a commodity-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed, and the contract price is recognized in the respective line item in our Consolidated Statement of Income representing the actual price of the underlying goods being delivered.

Unrealized gains and losses on physically settled commodity-related derivative contracts for commodity sales transactions are recognized in Net gain (loss) on commodity derivatives in our Consolidated Statement of Income. Realized and unrealized gains and losses on non-designated commodity-related derivative contracts for commodity sales transactions that are financially settled are reported in Net gain (loss) on commodity derivatives in our Consolidated Statement of Income. Net gains and losses on derivatives for shrink gas purchases for processing plants are reported in Net processing commodity expenses in our Consolidated Statement of Income.

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. (See Note 16 – Derivatives.)

We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Derivative assets; Regulatory assets, deferred charges, and other; Derivative liabilities; or Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet. These amounts are presented on a net basis and reflect the netting of asset and liability positions permitted under the terms of master netting arrangements and cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades.

The accounting for the changes in fair value of a commodity derivative can be summarized as follows:

Derivative Treatment	Accounting Method
Normal purchases and normal sales exception	Accrual accounting
Designated in a qualifying hedging relationship	Hedge accounting
All other derivatives	Mark-to-market accounting

We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected in our Consolidated Balance Sheet after the initial election of the exception.

We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe

87

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Net gain (loss) on commodity derivatives in our Consolidated Statement of Income.

For commodity derivatives designated as a cash flow hedge, the change in fair value of the derivative is reported in Accumulated other comprehensive income (loss) (AOCI) in our Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects earnings. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in Net gain (loss) on commodity derivatives in our Consolidated Statement of Income at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by us. As of December 31, 2022 and 2021, we are not applying hedge accounting to any commodity derivative instruments.

Interest capitalized

We capitalize interest during construction on major projects with construction periods of at least 3 months and a total project cost in excess of $1 million. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds (equity AFUDC). The latter is included in Other income (expense) – net below Operating income (loss) in our Consolidated Statement of Income. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on our average interest rate on debt.

Income taxes

We include the operations of our domestic corporate subsidiaries and income from our subsidiary partnerships in our consolidated federal income tax return and also file tax returns in various foreign and state jurisdictions as required. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of our assets and liabilities. Our judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.

Earnings (loss) per common share

Basic earnings (loss) per common share in our Consolidated Statement of Income is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share in our Consolidated Statement of Income primarily includes any dilutive effect of nonvested restricted stock units and stock options. Diluted earnings (loss) per common share is calculated using the treasury-stock method.

Cash and cash equivalents

Cash and cash equivalents in our Consolidated Balance Sheet consist of highly liquid investments with original maturities of three months or less when acquired.

Accounts receivable

Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts, considering current expected credit losses using a forward-looking “expected loss” model, the financial condition of our customers, and the age of past due accounts. The majority of our trade receivable balances are due within 30 days. We monitor the credit quality of our counterparties through review of collection trends, credit ratings, and other analyses, such as bankruptcy monitoring. Financial assets from our natural gas transmission and storage business, gathering, processing and transportation business, marketing

88

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

business, and upstream operations are segregated into separate pools for evaluation due to different counterparty risks inherent in each business. Changes in counterparty risk factors could lead to reassessment of the composition of our financial assets as separate pools or the need for additional pools. We calculate our allowance for credit losses incorporating an aging method. In estimating our expected credit losses, we utilize historical loss rates over many years, which include periods of both high and low commodity prices. Commodity prices could have a significant impact on a portion of our gathering and processing and upstream counterparties’ financial health and ability to satisfy current obligations. Our expected credit loss estimate considers both internal and external forward-looking commodity price expectations, as well as counterparty credit ratings, and factors impacting their near-term liquidity. In addition, our expected credit loss estimate considers potential contractual, physical, and commercial protections and outcomes in the case of a counterparty bankruptcy. The physical location and nature of our services help to mitigate collectability concerns of our gathering and processing producer customers. Our gathering lines in many cases are physically connected to the customers’ wellheads and pads, and there may not be alternative gathering lines nearby. The construction of gathering systems is capital intensive and it would be costly for others to replicate, especially considering the depletion to date of the associated reserves. As a result, we play a critical role in getting customers’ production from the wellhead to a marketable condition and location. This tends to reduce collectability risk as our services enable producers to generate operating cash flows. Commodity price movements generally do not impact the majority of our natural gas transmission businesses customers’ financial condition.

We also provide marketing and risk management services to retail and wholesale gas marketers, utility companies, upstream producers, and industrial customers. These counterparties utilize netting agreements that enable us to net receivables and payables by counterparty upon settlement. We also net across product lines and against cash collateral received to collateralize receivable positions, provided the netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, our counterparties are settled net, they are recorded on a gross basis in our Consolidated Balance Sheet as accounts receivable and accounts payable.

We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. We do not have a material amount of significantly aged receivables at December 31, 2022 and 2021.

Inventories

Inventories in our Consolidated Balance Sheet primarily consist of natural gas in underground storage, NGLs, and materials and supplies and primarily are stated at the lower of cost or net realizable value. The cost of inventories is primarily determined using the average-cost method. Any lower of cost or net realizable value adjustments are included in Product sales (for natural gas marketing inventory as these sales are presented net of the related costs) or in Product costs for NGL inventory.

Property, plant, and equipment

Property, plant, and equipment is initially recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values.

As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply an accelerated depreciation method.

We follow the successful efforts method of accounting for our undivided interest in upstream properties. Our oil and gas producing property costs are depreciated using a units of production method.

Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation. Gains or losses from the ordinary sale or retirement of property,

89

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

plant, and equipment for nonregulated assets are primarily recorded in Other (income) expense – net included in Operating income (loss) in our Consolidated Statement of Income.

Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment.

We record a liability and increase the basis in the underlying asset for the present value of each expected future ARO at the time the liability is initially incurred, typically when the asset is acquired or constructed. For our upstream properties, the ARO is recorded based on our working interest in the underlying properties. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset as we expect to recover these amounts in future rates. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in our Consolidated Statement of Income, except for regulated entities, for which the increase in the liability results in a corresponding increase to a regulatory asset. The regulatory asset is amortized commensurate with our collection of those costs in rates.

Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium.

Intangible assets

Our intangible assets included within Intangible assets – net of accumulated amortization in our Consolidated Balance Sheet are primarily related to gas gathering, processing, and fractionation customer relationships. Our intangible assets are generally amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life.

Impairment of property, plant, and equipment, intangible assets, and investments

We evaluate our property, plant, and equipment and intangible assets for impairment when, in our judgment, events or circumstances, including probable abandonment, indicate that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes, including selling the assets in the near term or holding them for their remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment to be recognized in our consolidated financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.

For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.

We evaluate our investments for impairment when, in our judgment, events or circumstances indicate that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in our consolidated financial statements as an impairment charge.

90

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Judgment and assumptions are inherent in our estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.

Equity-method investment basis differences

Differences between the carrying value of our equity-method investments and our underlying equity in the net assets of investees are accounted for as if the investees were consolidated subsidiaries. Equity earnings (losses) in our Consolidated Statement of Income includes our allocable share of net income (loss) of investees adjusted for any depreciation and amortization, as applicable, associated with basis differences.

Leases

We recognize a lease liability with an offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases based on the present value of the future lease payments. We have elected to combine lease and nonlease components for all classes of leased assets in our calculation of the lease liability and the offsetting right-of-use asset.

Our lease agreements require both fixed and variable periodic payments, with initial terms typically ranging from one year to 20 years. Payment provisions in certain of our lease agreements contain escalation factors which may be based on stated rates or a change in a published index at a future time. The amount by which a lease escalates based on the change in a published index, which is not known at lease commencement, is considered a variable payment and is not included in the present value of the future lease payments, which only includes those that are stated or can be calculated based on the lease agreement at lease commencement. In addition to the noncancellable periods, many of our lease agreements provide for one or more extensions of the lease agreement for periods ranging from one year in length to an indefinite number of times following the specified contract term. Other lease agreements provide for extension terms that allow us to utilize the identified leased asset for an indefinite period of time so long as the asset continues to be utilized in our operations. In consideration of these renewal features, we assess the term of the lease agreements, which includes using judgment in the determination of which renewal periods and termination provisions, when at our sole election, will be reasonably certain of being exercised. Periods after the initial term or extension terms that allow for either party to the lease to cancel the lease are not considered in the assessment of the lease term. Additionally, we have elected to exclude leases with an original term of one year or less, including renewal periods, from the calculation of the lease liability and the offsetting right-of-use asset.

We use judgment in determining the discount rate upon which the present value of the future lease payments is determined. This rate is based on a collateralized interest rate corresponding to the term of the lease agreement using company, industry, and market information available.

When permitted under our lease agreements, we may sublease certain unused office space for fixed periods that could extend up to the length of the original lease agreement.

Pension and other postretirement benefits

The funded status of each of the pension and other postretirement benefit plans is recognized separately in our Consolidated Balance Sheet as either an asset or liability. The plans’ benefit obligations and net periodic benefit costs (credits) are actuarially determined and impacted by various assumptions and estimates.

The discount rates are determined separately for each of our pension and other postretirement benefit plans based on an approach specific to our plans. The year-end discount rates are determined considering a yield curve comprised of high-quality corporate bonds and the timing of the expected benefit cash flows of each plan.

The expected long-term rates of return on plan assets are determined by combining a review of the historical returns within the portfolio, the investment strategy included in the plans’ investment policy statement, and capital

91

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

market projections for the asset classes in which the portfolio is invested, as well as the weighting of each asset class.

Unrecognized actuarial gains and losses are deferred and recorded in AOCI or, for Transco and Northwest Pipeline, as a regulatory asset or liability, until amortized as a component of net periodic benefit cost (credit). The unrecognized net actuarial losses deferred in AOCI at December 31, 2022 and 2021 were $18 million and $30 million, respectively. Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of plan assets are amortized over the participants’ average remaining future years of service, which is approximately 10 years for our pension plans and approximately 5 years for our other postretirement benefit plan.

The expected return on plan assets component of net periodic benefit cost (credit) is calculated using the market-related value of plan assets. For our pension plans, the market-related value of plan assets is equal to the fair value of plan assets adjusted to reflect the amortization of gains or losses associated with the difference between the expected and actual return on plan assets over a 5-year period. Additionally, the market-related value of assets may be no more than 110 percent or less than 90 percent of the fair value of plan assets at the beginning of the year. The market-related value of plan assets for our other postretirement benefit plan is equal to the unadjusted fair value of plan assets at the beginning of the year.

Contingent liabilities

We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable, and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.

Treasury stock

Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as Treasury stock, at cost in our Consolidated Balance Sheet. Gains and losses on the subsequent reissuance of shares are credited or charged to Capital in excess of par value in our Consolidated Balance Sheet using the average-cost method.

Cash flows from revolving credit facility and commercial paper program

Proceeds and payments related to borrowings under our revolving credit facility are reflected in the financing activities in our Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in our Consolidated Statement of Cash Flows on a net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See Note 12 – Debt and Banking Arrangements.)

Note 2 – Variable Interest Entities

Consolidated VIEs

As of December 31, 2022, we consolidate the following VIEs:

Northeast JV

We own a 65 percent interest in the Northeast JV, a subsidiary that is a VIE due to certain of our voting rights being disproportionate to our obligation to absorb losses and substantially all of the Northeast JV’s activities being

92

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

performed on our behalf. We are the primary beneficiary because we have the power to direct the activities that most significantly impact the Northeast JV’s economic performance. The Northeast JV provides midstream services for producers in the Marcellus Shale and Utica Shale regions. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis.

Gulfstar One

We own a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating-production system, Gulfstar FPS, and associated pipelines that provide production handling and gathering services in the eastern deepwater Gulf of Mexico. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance.

Cardinal

We own a 66 percent interest in Cardinal, a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner.

The following table presents amounts included in the Consolidated Balance Sheet that are only for the use or obligation of our consolidated VIEs:

	December 31,
	2022		2021
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	49	$	78
Trade accounts and other receivables – net	136		132
Inventories	4		3
Other current assets and deferred charges	7		7
Property, plant, and equipment – net	5,154		5,295
Intangible assets – net of accumulated amortization	2,158		2,267
Regulatory assets, deferred charges, and other	29		20
Accounts payable	(76)		(61)
Accrued and other current liabilities	(34)		(29)
Regulatory liabilities, deferred income, and other	(275)		(287)

Nonconsolidated VIEs

Targa Train 7

We own a 20 percent interest in Targa Train 7, which provides fractionation services at Mont Belvieu, Texas, and is a VIE due primarily to our limited participating rights as the minority equity holder. At December 31, 2022, the carrying value of our investment in Targa Train 7 was $46 million. Our maximum exposure to loss is limited to the carrying value of our investment.

93

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Brazos Permian II

We own a 15 percent interest in Brazos Permian II, which provides gathering and processing services in the Delaware basin and is a VIE due primarily to our limited participating rights as the minority equity holder. At December 31, 2022, the carrying value of our investment in Brazos Permian II was $16 million. Our maximum exposure to loss is limited to the carrying value of our investment.

Note 3 – Acquisitions

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 (Trace) for $972 million of cash funded with cash on hand and proceeds from issuance of commercial paper (Trace Acquisition). 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.

During the period from the acquisition date of April 29, 2022 to December 31, 2022, the operations acquired in the Trace Acquisition contributed Revenues of $148 million and Modified EBITDA (as defined in Note 18 – Segment Disclosures) of $73 million.

Acquisition-related costs for the Trace Acquisition for the period from the acquisition date of April 29, 2022 to December 31, 2022 of $8 million are reported within our West segment and included in Selling, general, and administrative expenses in our Consolidated Statement of Income.

We accounted for the Trace Acquisition as a business combination, which requires, among other things, that identifiable assets acquired and liabilities assumed be recognized at their acquisition date fair values. The valuation techniques used consisted of the income approach (excess earnings method) for valuation of intangible assets and depreciated replacement costs for property, plant, and equipment.

The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in the West segment, and liabilities assumed at April 29, 2022. The fair value of accounts receivable acquired equals contractual amounts receivable.

	(Millions)
Cash and cash equivalents	$	39
Trade accounts and other receivables – net	18
Property, plant, and equipment – net	448
Intangible assets – net of accumulated amortization	472
Other noncurrent assets	20
Total assets acquired	$	997
Accounts payable	$	12
Accrued and other current liabilities	5
Other noncurrent liabilities	8
Total liabilities assumed	$	25
Net assets acquired	$	972

Intangible assets

Intangible assets recognized in the Trace Acquisition are related to contractual customer relationships from gas gathering agreements with our customers. The basis for determining the value of these intangible assets is estimated future net cash flows to be derived from acquired contractual customer relationships discounted using a risk-adjusted

94

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

discount rate. These intangible assets are being amortized on a straight-line basis over an initial period of 20 years which represents the term over which the contractual customer relationships are expected to contribute to our cash flows. Approximately 2 percent of the expected future revenues from these contractual customer relationships are impacted by our ability and intent to renew or renegotiate existing customer contracts. We expense costs incurred to renew or extend the terms of our gas gathering contracts with customers. Based on the estimated future revenues during the current contract periods (as estimated at the time of the acquisition), the weighted-average period prior to the next renewal or extension of the existing contractual customer relationships is approximately 19 years. See Note 10 – Intangible Assets.

Sequent Acquisition

On July 1, 2021, we closed on the acquisition of 100 percent of Sequent Energy Management, L.P. and Sequent Energy Canada, Corp (Sequent Acquisition). Total consideration for this acquisition was $159 million, which included $109 million related to working capital.

Operations acquired in the Sequent Acquisition focus on risk management and the marketing, trading, storage, and transportation of natural gas for a diverse set of natural gas and electric utilities, municipalities, power generators, and producers, as well as moving gas to markets through transportation and storage agreements on strategically positioned assets, including our Transco system. The purpose of the Sequent Acquisition was to expand our natural gas marketing activities as well as optimize our pipeline and storage capabilities with expansions into new markets to reach incremental gas-fired power generation, liquified natural gas exports, and future renewable natural gas and other emerging opportunities.

During the period from the acquisition date of July 1, 2021 to December 31, 2021, results for the operations acquired in the Sequent Acquisition included net Product sales of $(43) million (including $80 million of purchases from affiliates), Net gain (loss) on commodity derivatives of $(43) million, and unfavorable Modified EBITDA of $112 million. Both the Revenues and Modified EBITDA amounts reflect a net unrealized loss on commodity derivatives in Net gain (loss) on commodity derivatives of $(109) million for the period.

Acquisition-related costs for the Sequent Acquisition for the period from the acquisition date of July 1, 2021 to December 31, 2021 of $5 million are reported within our Gas & NGL Marketing Services segment and were included in Selling, general, and administrative expenses in our Consolidated Statement of Income for the year ended December 31, 2021.

95

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

We accounted for the Sequent Acquisition as a business combination. The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in the Gas & NGL Marketing Services segment, and liabilities assumed at July 1, 2021. The fair value of accounts receivable acquired equals contractual amounts receivable. The fair value of the intangible assets was measured using an income approach. The fair value of the inventory acquired was based on the market price of the natural gas in underground storage at the acquisition date. See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk for the valuation techniques used to measure fair value of derivative assets and liabilities.

	(Millions)
Cash and cash equivalents	$	8
Trade accounts and other receivables – net	498
Inventories	121
Derivative assets	57
Other current assets and deferred charges	4
Property, plant, and equipment – net	5
Intangible assets – net of accumulated amortization	306
Other noncurrent assets	3
Commodity derivatives included in other noncurrent assets	49
Total assets acquired	$	1,051
Accounts payable	$	514
Derivative liabilities	116
Accrued and other current liabilities	46
Other noncurrent liabilities	1
Commodity derivatives included in other noncurrent liabilities	215
Total liabilities assumed	$	892
Net assets acquired	$	159

Accounts receivable and accounts payable

The operations acquired in the Sequent Acquisition provide services to retail and wholesale gas marketers, utility companies, upstream producers, and industrial customers. See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies for our policy regarding netting receivables and payables.

Intangible assets

Intangible assets are primarily related to transportation and storage capacity contracts. The basis for determining the value of these intangible assets was estimated future net cash flows to be derived from acquired transportation and storage capacity contracts that provide future economic benefits due to their market location, discounted using an industry weighted-average cost of capital. This intangible asset is being amortized based on the expected benefit period over which the underlying contracts are expected to contribute to our cash flows ranging from 1 year to 8 years. As a result, we expect a significant portion of the amortization to be recognized within the first few years of this range. See Note 10 – Intangible Assets.

Commodity derivatives

We are exposed to commodity price risk. To manage this volatility, we use various contracts in our marketing and trading activities that generally meet the definition of derivatives. We enter into commodity-related derivatives to economically hedge exposures to natural gas and retain exposure to price changes that can, in a volatile energy market, be material and can adversely affect our results of operations; see Note 1 – General, Description of

96

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Business, Basis of Presentation, and Summary of Significant Accounting Policies for our accounting policy for derivatives.

Supplemental Pro Forma

The following pro forma Revenues and Net income (loss) attributable to The Williams Companies, Inc. in 2022, 2021, and 2020, are presented as if the Trace Acquisition had been completed on January 1, 2021, and the Sequent Acquisition had been completed on January 1, 2020. These pro forma amounts are not necessarily indicative of what the actual results would have been if the Trace Acquisition and Sequent Acquisition had in fact occurred on the dates or for the periods indicated, nor do they purport to project Revenues or Net income (loss) attributable to The Williams Companies, Inc. for any future periods or as of any date. These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result from the transaction or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements.

	Year Ended December 31, 2022
	As Reported		Pro Forma Trace (1)				Pro Forma Combined
	(Millions)
Revenues	$	10,965	$	45			$	11,010
Net income (loss) attributable to The Williams Companies, Inc.	2,049		18				2,067
	Year Ended December 31, 2021
	As Reported		Pro Forma Trace		Pro Forma Sequent (2)		Pro Forma Combined
	(Millions)
Revenues	$	10,627	$	118	$	188	$	10,933
Net income (loss) attributable to The Williams Companies, Inc.	1,517		42		4		1,563
	Year Ended December 31, 2020
	As Reported				Pro Forma Sequent		Pro Forma Combined
	(Millions)
Revenues	$	7,719			$	74	$	7,793
Net income (loss) attributable to The Williams Companies, Inc.	211				(13)		198

(1)Excludes results from operations acquired in the Trace Acquisition for the period beginning on the acquisition date of April 29, 2022, as these results are included in the amounts as reported.

(2)Excludes results from operations acquired in the Sequent Acquisition for the period beginning on the acquisition date of July 1, 2021, as these results are included in the amounts as reported.

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 (NorTex Asset Purchase) for approximately $424 million. These assets are included in the Transmission & Gulf of Mexico segment.

97

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Note 4 – Related Party Transactions

Transactions with Equity-Method Investees

We have expenses associated with our equity-method investees of $1.346 billion, $948 million, and $348 million for 2022, 2021, and 2020, respectively in our Consolidated Statement of Income. Substantially all of these expenses are included in Product costs. We also have revenue from our equity-method investees of $76 million, $46 million, and $26 million for 2022, 2021, and 2020, respectively. In addition, we have $17 million and $9 million included in Accounts receivable and $87 million and $89 million included in Accounts payable in our Consolidated Balance Sheet with our equity-method investees at December 31, 2022 and 2021, respectively.

We have operating agreements with certain equity-method investees. These operating agreements typically provide for reimbursement or payment to us for certain direct operational payroll and employee benefit costs, materials, supplies, and other charges and also for management services. The total charges to equity-method investees for these fees are $65 million, $70 million, and $79 million for 2022, 2021, and 2020, respectively.

Board of Directors

Two members of our Board of Directors are also executive officers at certain of our counterparties. We recorded $180 million in Product sales and $86 million in Product costs in our Consolidated Statement of Income from these companies for the purchase and sale of natural gas for 2022.

98

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Note 5 – Revenue Recognition

Revenue by Category

The following table presents our revenue disaggregated by major service line:

	Transco		Northwest Pipeline		Gulf of Mexico Midstream and Storage		Northeast Midstream		West Midstream		Gas & NGL Marketing Services		Other		Eliminations		Total
	(Millions)
2022
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	2,696	$	443	$	—	$	—	$	—	$	—	$	—	$	(72)	$	3,067
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		365		1,395		1,476		—		—		(164)		3,072
Commodity consideration	—		—		64		14		182		—		—		—		260
Other	10		—		27		233		54		3		—		(19)		308
Total service revenues	2,706		443		456		1,642		1,712		3		—		(255)		6,707
Product sales	179		—		251		134		841		10,768		706		(1,813)		11,066
Total revenues from contracts with customers	2,885		443		707		1,776		2,553		10,771		706		(2,068)		17,773
Other revenues (1)	24		4		10		26		8		7,929		(55)		(11)		7,935
Other adjustments (2)	—		—		—		—		—		(15,467)		—		724		(14,743)
Total revenues	$	2,909	$	447	$	717	$	1,802	$	2,561	$	3,233	$	651	$	(1,355)	$	10,965
2021
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	2,547	$	441	$	—	$	—	$	—	$	—	$	—	$	(33)	$	2,955
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		344		1,308		1,184		—		—		(130)		2,706
Commodity consideration	—		—		52		7		179		—		—		—		238
Other	10		—		22		195		52		3		1		(19)		264
Total service revenues	2,557		441		418		1,510		1,415		3		1		(182)		6,163
Product sales	88		—		269		99		643		6,404		333		(1,215)		6,621
Total revenues from contracts with customers	2,645		441		687		1,609		2,058		6,407		334		(1,397)		12,784
Other revenues (1)	10		3		8		25		(32)		2,632		11		(13)		2,644
Other adjustments (2)	—		—		—		—		—		(4,828)		—		27		(4,801)
Total revenues	$	2,655	$	444	$	695	$	1,634	$	2,026	$	4,211	$	345	$	(1,383)	$	10,627

99

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

	Transco		Northwest Pipeline		Gulf of Mexico Midstream and Storage		Northeast Midstream		West Midstream		Gas & NGL Marketing Services		Other		Eliminations		Total
	(Millions)
2020
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	2,404	$	449	$	—	$	—	$	—	$	—	$	—	$	(7)	$	2,846
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		348		1,279		1,226		—		—		(97)		2,756
Commodity consideration	—		—		21		7		101		—		—		—		129
Other	10		—		27		164		35		32		1		(16)		253
Total service revenues	2,414		449		396		1,450		1,362		32		1		(120)		5,984
Product sales	80		—		114		57		152		1,602		—		(336)		1,669
Total revenues from contracts with customers	2,494		449		510		1,507		1,514		1,634		1		(456)		7,653
Other revenues (1)	10		—		9		22		9		(3)		33		(14)		66
Total revenues	$	2,504	$	449	$	519	$	1,529	$	1,523	$	1,631	$	34	$	(470)	$	7,719

______________________________

(1)Revenues not derived from contracts with customers primarily consist of physical product sales related to derivative contracts, realized and unrealized gains and losses associated with our derivative contracts, which are reported in Net gain (loss) on commodity derivatives in the Consolidated Statement of Income, management fees that we receive for certain services we provide to operated equity-method investments, and leasing revenues associated with our headquarters building.

(2)Other adjustments reflect certain costs of Gas & NGL Marketing Services’ risk management activities. As we are acting as agent for natural gas marketing customers or engage in energy trading activities, the resulting revenues are presented net of the related costs of those activities in the Consolidated Statement of Income (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).

Contract Assets

The following table presents a reconciliation of our contract assets:

	Year Ended December 31,
	2022		2021
	(Millions)
Balance at beginning of year	$	22	$	12
Revenue recognized in excess of amounts invoiced	208		184
Minimum volume commitments invoiced	(201)		(174)
Balance at end of year	$	29	$	22

100

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Contract Liabilities

The following table presents a reconciliation of our contract liabilities:

	Year Ended December 31,
	2022		2021
	(Millions)
Balance at beginning of year	$	1,126	$	1,209
Payments received and deferred	180		116
Significant financing component	9		10
Contract liability acquired	2		1
Recognized in revenue	(274)		(210)
Balance at end of year	$	1,043	$	1,126

Remaining Performance Obligations

Remaining performance obligations primarily include reservation charges on contracted capacity for our gas pipeline firm transportation contracts with customers, storage capacity contracts, long-term contracts containing minimum volume commitments associated with our midstream businesses, and fixed payments associated with offshore production handling. For our interstate natural gas pipeline businesses, remaining performance obligations reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes are not currently known.

Our remaining performance obligations exclude variable consideration, including contracts with variable consideration for which we have elected the practical expedient for consideration recognized in revenue as billed. Certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation amounts as of December 31, 2022, do not consider potential future performance obligations for which the renewal has not been exercised and exclude contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service. Consideration received prior to December 31, 2022, that will be recognized in future periods is also excluded from our remaining performance obligations and is instead reflected in contract liabilities.

The following table presents the amount of the contract liabilities balance expected to be recognized as revenue when performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2022.

	Contract Liabilities		Remaining Performance Obligations
	(Millions)
2023 (one year)	$	142	$	3,643
2024 (one year)	122		3,388
2025 (one year)	117		3,149
2026 (one year)	112		2,520
2027 (one year)	101		2,415
Thereafter	449		14,675
Total	$	1,043	$	29,790

101

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Note 6 – Provision (Benefit) for Income Taxes

The Provision (benefit) for income taxes includes:

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Current:
Federal	$	(25)	$	(1)	$	(29)
State	19		3		—
	(6)		2		(29)
Deferred:
Federal	424		421		98
State	7		88		10
	431		509		108
Provision (benefit) for income taxes	$	425	$	511	$	79

Reconciliations from the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes are as follows:

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Provision (benefit) at statutory rate	$	534	$	435	$	58
Increases (decreases) in taxes resulting from:
State income taxes (net of federal benefit)	113		71		6
State deferred income tax rate change	(92)		—		—
Federal valuation allowance	(70)		3		1
Federal settlements	(45)		—		—
Impact of nontaxable noncontrolling interests	(14)		(9)		3
Other – net	(1)		11		11
Provision (benefit) for income taxes	$	425	$	511	$	79

Income (loss) before income taxes includes less than $1 million of foreign income in 2022, and $2 million and $1 million of foreign loss in 2021 and 2020, respectively.

The State deferred income tax rate change benefit of $92 million is related to a decrease in our estimate of the deferred state income tax rate (net of federal effect) driven primarily by the enacted decline in the Pennsylvania state income tax rate over the next several years.

During the course of audits of our business by domestic and foreign tax authorities, we frequently face challenges regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. In evaluating the liability associated with our various filing positions, we apply the two-step process of recognition and measurement. In association with this liability, we record an estimate of related interest and tax exposure as a component of our tax provision. The impact of this accrual is included within Other – net in our reconciliation of the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes.

102

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Significant components of Deferred income tax liabilities are as follows:

	December 31,
	2022		2021
	(Millions)
Gross deferred income tax liabilities:
Property, plant and equipment	$	3,171	$	2,777
Investments	1,784		1,669
Other	138		154
Total gross deferred income tax liabilities	5,093		4,600
Gross deferred income tax assets:
Accrued liabilities	1,108		872
Foreign tax credits	91		140
Federal loss carryovers	730		879
State losses and credits	356		421
Other	121		132
Total gross deferred income tax assets	2,406		2,444
Less valuation allowance	200		297
Net deferred income tax assets	2,206		2,147
Deferred income tax liabilities	$	2,887	$	2,453

The valuation allowance at December 31, 2022 and 2021 serves to reduce the available deferred income tax assets to an amount that will, more likely than not, be realized. We considered all available positive and negative evidence, which incorporates available tax planning strategies, and management’s estimate of future reversals of existing taxable temporary differences, and have determined that a portion of our deferred income tax assets related to the Foreign tax credits and State losses and credits may not be realized. In 2022, we released $70 million of valuation allowance upon determining we expect to utilize additional foreign tax credits prior to expiration between 2024 and 2025. The amounts presented in the table above are, with respect to state items, before any federal benefit. The change from prior year for the State losses and credits reflects increases in losses and credits generated in the current and prior years less losses and/or credits utilized in the current year. We have loss and credit carryovers in multiple state taxing jurisdictions. These attributes generally expire between 2023 and 2041 with some carryovers having indefinite carryforward periods.

Federal loss carryovers at the end of 2022 include deferred tax assets on net operating loss carryovers of $705 million with no expiration date. Deferred tax assets on charitable contributions of $25 million are expected to be utilized by us prior to expiring between 2023 and 2027.

Cash payments for income taxes (net of refunds) were $13 million in 2022. Cash refunds for income taxes (net of payments) were $45 million and $40 million in 2021 and 2020, respectively.

During the second quarter of 2022, we finalized settlements for 2011 through 2014 on certain contested matters with the Internal Revenue Service (IRS) that resulted in a 2022 year-to-date tax benefit of approximately $45 million. In 2022, we received cash refunds related to these settlements totaling $7 million.

We recognize related interest and penalties as a component of Provision (benefit) for income taxes. Total interest and penalties recognized as part of income tax provision were benefits of $3 million in 2022 and $1 million in each of 2021 and 2020. There are no interest or penalties relating to uncertain tax positions accrued as of December 31, 2022 and $4 million of interest was accrued as of December 31, 2021.

Consolidated U.S. Federal income tax returns are open to IRS examination for years after 2017. As of December 31, 2022, examination of 2018 is currently in process, with the statute extended to September 30, 2023. We do not expect material changes in our financial position resulting from this examination. The statute of limitations for most states expires one year after expiration of the IRS statute.

103

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Note 7 – Employee Benefit Plans

Pension Plans

We have noncontributory defined benefit pension plans for eligible employees hired prior to January 1, 2019. Eligible employees earn compensation credits based on a cash balance formula. As of January 1, 2020, certain active employees are no longer eligible to receive compensation credits.

Other Postretirement Benefits

We provide subsidized retiree medical benefits to a closed group of participants as well as retiree life insurance benefits to eligible participants. Medical benefits for Medicare eligible participants are paid through contributions to health reimbursement accounts. Benefits for all other participants are provided through a self-insured medical plan, which includes participant contributions and contains other cost-sharing features such as deductibles, co-payments, and co-insurance.

Defined Contribution Plan

We have a defined contribution plan for the benefit of substantially all employees. Plan participants may contribute a portion of their compensation on a pre-tax or after-tax basis. Generally, we match employee contributions up to 6 percent of eligible compensation. Additionally, eligible active employees that do not receive compensation credits under the defined benefit pension plan are eligible for an additional annual fixed-percentage contribution made by us to the defined contribution plan. Our contributions charged to expense were $53 million in 2022, $45 million in 2021, and $42 million in 2020.

104

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Funded Status

The following table presents the changes in benefit obligations and plan assets for pension benefits and other postretirement benefits for the years indicated:

	Pension Benefits				Other Postretirement Benefits
	2022		2021		2022		2021
	(Millions)
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,133	$	1,183	$	200	$	220
Service cost	28		30		1		1
Interest cost	31		28		6		5
Plan participants’ contributions	—		—		2		2
Benefits paid	(78)		(83)		(12)		(14)
Net actuarial loss (gain) (1)	(162)		(21)		(45)		(14)
Settlements	(12)		(4)		—		—
Net increase (decrease) in benefit obligation	(193)		(50)		(48)		(20)
Benefit obligation at end of year	940		1,133		152		200
Change in plan assets:
Fair value of plan assets at beginning of year	1,336		1,357		287		278
Actual return on plan assets	(132)		62		(27)		16
Employer contributions	3		4		3		5
Plan participants’ contributions	—		—		2		2
Benefits paid	(78)		(83)		(12)		(14)
Settlements	(12)		(4)		—		—
Net increase (decrease) in fair value of plan assets	(219)		(21)		(34)		9
Fair value of plan assets at end of year	1,117		1,336		253		287
Funded status — overfunded (underfunded)	$	177	$	203	$	101	$	87
Amounts recognized in the Consolidated Balance Sheet:
Noncurrent assets	$	201	$	229	$	105	$	91
Current liabilities	(2)		(3)		(4)		(4)
Noncurrent liabilities	(22)		(23)		—		—
Funded status — overfunded (underfunded)	$	177	$	203	$	101	$	87
Accumulated benefit obligation	$	930	$	1,118

____________

(1)    2022 amounts are due primarily to the following factors: Pension benefits - discount rate assumptions, partially offset by change in interest crediting rate assumption; Other Postretirement Benefits - discount rate assumption. 2021 amounts are due primarily to the following factors: Pension Benefits - discount rate assumptions, partially offset by experience-related items; Other Postretirement Benefits - discount rate assumption and experience-related items.

105

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

The following table summarizes information for pension plans with obligations in excess of plan assets at December 31.

	2022		2021
	(Millions)
Projected benefit obligation	$	24	$	26
Accumulated benefit obligation	22		22
Fair value of plan assets	—		—

Pre-tax amounts recognized in Accumulated other comprehensive income (loss) at December 31 are as follows:

	Pension Benefits				Other Postretirement Benefits
	2022		2021		2022		2021
	(Millions)
Net actuarial gain (loss)	$	(45)	$	(46)	$	18	$	4

Additionally, as of December 31, 2022 and 2021, we have $130 million and $150 million, respectively, of pension and other postretirement plan amounts included in regulatory liabilities associated with our gas pipeline companies.

Net Periodic Benefit Cost (Credit)

Net periodic benefit cost (credit) for the years ended December 31 consist of the following:

	Pension Benefits						Other Postretirement  Benefits
	2022		2021		2020		2022		2021		2020
	(Millions)
Components of net periodic benefit cost (credit):
Service cost	$	28	$	30	$	31	$	1	$	1	$	1
Interest cost	31		28		36		6		5		7
Expected return on plan assets	(44)		(43)		(53)		(10)		(10)		(11)
Amortization of net actuarial loss	12		14		21		—		—		—
Net actuarial loss from settlements	3		1		9		—		—		—
Reclassification to regulatory liability	—		—		—		1		2		2
Net periodic benefit cost (credit) (1)	$	30	$	30	$	44	$	(2)	$	(2)	$	(1)

____________

(1)    Components other than Service cost are included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Income.

106

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Items Recognized in Other Comprehensive Income (Loss)

Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) before taxes for the years ended December 31 consist of the following:

	Pension Benefits						Other Postretirement  Benefits
	2022		2021		2020		2022		2021		2020
	(Millions)
Net actuarial gain (loss) arising during the year	$	(14)	$	40	$	112	$	14	$	29	$	(4)
Amortization of net actuarial loss	12		14		21		—		—		—
Net actuarial loss from settlements	3		1		9		—		—		—
Total recognized in Other comprehensive income (loss)	$	1	$	55	$	142	$	14	$	29	$	(4)

Key Assumptions

The weighted-average assumptions utilized to determine benefit obligations and Net periodic benefit cost (credit) as of December 31 are as follows:

	Pension Benefits						Other Postretirement  Benefits
	2022		2021		2020		2022		2021		2020
Benefit obligations:
Discount rate	5.16	%	2.82	%	2.45	%	5.20	%	2.93	%	2.59	%
Rate of compensation increase	3.58		3.67		3.76		N/A		N/A		N/A
Cash balance interest crediting rate	3.50		3.00		3.00		N/A		N/A		N/A
Net periodic benefit cost (credit):
Discount rate	2.84	%	2.45	%	3.08	%	2.93	%	2.59	%	3.27	%
Expected long-term rate of return on plan assets	3.81		3.69		4.67		3.67		3.61		4.39
Rate of compensation increase	3.67		3.76		3.68		N/A		N/A		N/A
Cash balance interest crediting rate	3.00		3.00		3.50		N/A		N/A		N/A

We use mortality tables issued by the Society of Actuaries to measure the benefit obligations.

The assumed health care cost trend rate for 2023 is 6.8 percent. This rate decreases to 4.5 percent by 2032.

Plan Assets

The plans’ investment objectives include a framework to manage the volatility of the plans’ funded status and minimize future cash contributions. The plans follow a policy of diversifying the investments across various asset classes, strategies, and investment managers.

The investment policy for the pension plans includes target asset allocation percentages as well as permitted and prohibited investments designed to mitigate risks associated with investing. The December 31, 2022, target asset allocation was 25 percent equity securities and 75 percent fixed income securities, including investments in equity and fixed income mutual funds, commingled investment funds, and separate accounts.

107

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

The fair values of our pension and other postretirement benefits plan assets by asset class at December 31 are as follows: 

	2022
	Pension Benefits						Other Postretirement Benefits
	Level 1 (1)		Level 2 (2)		Total		Level 1 (1)		Level 2 (2)		Total
	(Millions)
Cash management funds	$	45	$	—	$	45	$	105	$	—	$	105
Government debt securities	58		18		76		8		3		11
Corporate debt securities	—		284		284		—		39		39
Other	1		4		5		—		—		—
	$	104	$	306	410		$	113	$	42	155
Commingled investment funds (3):
Equities					273						38
Fixed income					434						60
Total assets at fair value					$	1,117					$	253

	2021
	Pension Benefits						Other Postretirement Benefits
	Level 1 (1)		Level 2 (2)		Total		Level 1 (1)		Level 2 (2)		Total
	(Millions)
Cash management funds	$	37	$	—	$	37	$	14	$	—	$	14
Equity securities	42		19		61		39		10		49
Government debt securities	99		28		127		13		4		17
Corporate debt securities	—		350		350		—		47		47
Mutual fund - Municipal bonds	—		—		—		59		—		59
Other	(3)		2		(1)		(1)		—		(1)
	$	175	$	399	574		$	124	$	61	185
Commingled investment funds (3):
Equities					288						39
Fixed income					474						63
Total assets at fair value					$	1,336					$	287

____________

(1)    Level 1 includes assets with fair values based on quoted prices in active markets for identical assets. Cash management funds, equity securities traded on U.S. exchanges, U.S. Treasury securities, and mutual funds are included in this level.

(2)    Level 2 includes assets with fair values determined by using significant other observable inputs. This level includes equity securities traded on active foreign exchanges and fixed income securities, other than U.S. Treasury securities, that are valued primarily using pricing models which incorporate observable inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads.

(3)    The commingled investment funds are measured at fair value using net asset value per share. Certain standard withdrawal restrictions generally apply, which may include redemption notification period restrictions ranging from 1 day to 15 days.

108

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Plan Benefit Payments and Employer Contributions

Following are the expected benefit payments, which reflect the same assumptions previously discussed and future service as appropriate.

	Pension Benefits		Other Postretirement Benefits
	(Millions)
2023	$	84	$	13
2024	83		13
2025	84		12
2026	81		12
2027	80		11
2028-2032	389		52

In 2023, we expect to contribute approximately $1 million to our pension plans and approximately $4 million to our other postretirement benefit plan.

Note 8 – Investing Activities

Investments

	Ownership Interest at December 31, 2022	December 31,
		2022		2021
		(Millions)
Equity method:
Appalachia Midstream Investments	(1)	$	2,975	$	3,056
RMM	50%	395		401
OPPL	50%	386		388
Blue Racer	50%	383		377
Discovery	60%	345		328
Gulfstream	50%	220		215
Laurel Mountain	69%	205		226
Other	Various	139		130
		5,048		5,121
Other		17		6
		$	5,065	$	5,127

___________

(1)Includes equity-method investments in multiple gathering systems in the Marcellus Shale region with an approximate average 66 percent interest.

Basis differential

The carrying value of our Appalachia Midstream Investments exceeds our portion of the underlying net assets by approximately $1.1 billion and $1.2 billion at December 31, 2022 and 2021, respectively. These differences were assigned at the acquisition date to property, plant, and equipment and customer relationship intangible assets. Certain of our other equity-method investments have a carrying value less than our portion of the underlying equity in the net assets primarily due to other than temporary impairments that we have recognized but that were not required to be recognized in the investees’ financial statements. These differences total approximately $1.1 billion and $1.2 billion at December 31, 2022 and 2021, respectively, and were assigned to property, plant, and equipment and customer relationship intangible assets. Differences in the carrying value of our equity-method investments and

109

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

our portion of the equity in the underlying net assets are generally amortized over the remaining useful lives of the associated underlying assets and included in Equity earnings (losses) within our Consolidated Statement of Income.

Purchases of and contributions to equity-method investments

We generally fund our portion of significant expansion or development projects of these investees through additional capital contributions. These transactions increased the carrying value of our investments and included:

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Appalachia Midstream Investments	$	83	$	84	$	116
Discovery	41		—		—
Cardinal Pipeline Company, LLC	16		—		—
Gulfstream	14		26		3
Blue Racer (1)	—		3		157
Other	12		2		49
	$	166	$	115	$	325

___________

(1)See following discussion in the section Acquisition of additional interests in BRMH below.

Acquisition of additional interests in BRMH

As of December 31, 2019, we effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent interest in Blue Racer Midstream Holdings, LLC (BRMH), whose primary asset is a 50 percent interest in Blue Racer. In November 2020, we paid $157 million, net of cash acquired, to acquire an additional 41 percent ownership interest in BRMH before acquiring the remaining interest of BRMH in September 2021. As such, we control and consolidate BRMH, reporting the 50 percent interest in Blue Racer as an equity-method investment. Since substantially all of the fair value of the BRMH assets acquired is concentrated in a single asset, the investment in Blue Racer, and we previously held a noncontrolling interest in BRMH, we recorded the November 2020 and September 2021 additional purchases of interests as asset acquisitions. Prior to November 2021 BRMH was named Caiman Energy II, LLC and was accounted for as an equity-method investment.

Dividends and distributions

The organizational documents of entities in which we have an equity-method investment generally require distribution of available cash to members on at least a quarterly basis. These transactions reduced the carrying value of our investments and included:

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Appalachia Midstream Investments	$	415	$	433	$	357
Laurel Mountain	112		33		31
Gulfstream	89		90		93
RMM	52		45		39
Blue Racer (1)	49		47		47
Discovery	49		44		21
OPPL	34		26		50
Other	65		39		15
	$	865	$	757	$	653

___________

(1)See previous discussion in the section Acquisition of additional interests in BRMH above.

110

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Equity Earnings (Losses)

Equity earnings (losses) in 2020 includes a $78 million loss associated with the first-quarter full impairment of goodwill recognized by our investee RMM, which was allocated entirely to our member interest per the terms of the membership agreement. Also included in 2020 are losses of $11 million, $26 million, and $10 million for our share of asset impairments at Laurel Mountain, Appalachia Midstream Investments, and Blue Racer, respectively.

Impairments of Equity-Method Investments

See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk for information regarding impairments of our equity-method investments of $1,046 million for 2020.

Summarized Financial Position and Results of Operations of All Equity-Method Investments

	December 31,
	2022		2021
	(Millions)
Assets (liabilities):
Current assets	$	964	$	743
Noncurrent assets	12,701		13,211
Current liabilities	(632)		(435)
Noncurrent liabilities	(3,789)		(3,774)

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Gross revenue	$	5,520	$	4,688	$	2,625
Operating income	1,268		1,191		508
Net income	1,102		1,006		459

Note 9 – Property, Plant, and Equipment

The following table presents nonregulated and regulated Property, plant, and equipment – net as presented on the Consolidated Balance Sheet for the years ended:

	Estimated Useful Life  (1) (Years)	Depreciation Rates (1) (%)	December 31,
			2022		2021
			(Millions)
Nonregulated:
Natural gas gathering and processing facilities	5 - 40		$	19,163	$	18,203
Construction in progress	Not applicable		997		331
Oil and gas properties	Units of production		874		572
Other	0 - 45		2,998		2,649
Regulated:
Natural gas transmission facilities		1.25 - 7.13	19,521		19,201
Construction in progress	Not applicable	Not applicable	708		475
Other	5 - 45	0.00 - 33.33	2,796		2,753
Total property, plant, and equipment, at cost			47,057		44,184
Accumulated depreciation and amortization			(16,168)		(14,926)
Property, plant, and equipment — net			$	30,889	$	29,258

__________

(1)    Estimated useful life and depreciation rates are presented as of December 31, 2022. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC.

111

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Depreciation and amortization expense for Property, plant, and equipment – net was $1.498 billion, $1.496 billion, and $1.393 billion in 2022, 2021, and 2020, respectively.

Regulated Property, plant, and equipment – net includes approximately $428 million and $468 million at December 31, 2022 and 2021, respectively, related to amounts in excess of the original cost of the regulated facilities within our gas pipeline businesses as a result of our prior acquisitions. This amount is being amortized over 40 years using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction.

Asset Retirement Obligations

Our accrued obligations primarily relate to offshore platforms and pipelines, oil and gas properties, gas transmission pipelines and facilities, underground storage caverns, gas processing, fractionation, and compression facilities, and gas gathering well connections and pipelines. At the end of the useful life of each respective asset, we are legally obligated to dismantle offshore platforms and appropriately abandon offshore pipelines, to remove certain components of gas transmission facilities from the ground, to restore land and remove surface equipment at gas processing, fractionation, and compression facilities, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, to plug storage caverns and remove any related surface equipment, and to plug producing wells and remove any related surface equipment.

The following table presents the significant changes to our ARO, of which $1.827 billion and $1.590 billion are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued and other current liabilities at December 31, 2022 and 2021, respectively.

	Year Ended December 31,
	2022		2021
	(Millions)
Balance at beginning of year	$	1,665	$	1,222
Liabilities incurred (1)	77		336
Liabilities settled	(22)		(25)
Accretion	85		73
Revisions (2)	109		59
Balance at end of year	$	1,914	$	1,665

___________

(1)Includes $307 million of ARO in 2021 related to acquired upstream properties.

(2)Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2022 revisions reflect changes in removal cost estimates and increases in inflation rates, partially offset by increases in discount rates. The 2021 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, and increases in inflation rates.

The funds Transco collects through a portion of its rates to fund its ARO are deposited into an external trust account dedicated to funding its ARO (ARO Trust). (See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) Under its current rate settlement, Transco’s annual funding obligation is approximately $16 million, with installments to be deposited monthly.

112

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Note 10 – Intangible Assets

The gross carrying amount and accumulated amortization of intangible assets, included in Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet, at December 31 are as follows:

	2022				2021
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
	(Millions)
Customer relationships	$	10,065	$	(2,801)	$	9,593	$	(2,448)
Transportation and storage capacity contracts	267		(172)		267		(14)
Other intangible assets	6		(2)		6		(2)
	$	10,338	$	(2,975)	$	9,866	$	(2,464)

Customer Relationships

Customer relationships primarily relate to gas gathering, processing, and fractionation contractual customer relationships recognized in acquisitions. Contractual customer relationships are being amortized on a straight-line basis over a period of 30 years for most acquisitions, which represents a portion of the term over which the contractual customer relationships are expected to contribute to our cash flows.

We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Although a significant portion of the expected future cash flows associated with these contractual customer relationships are dependent on our ability to renew or extend the arrangements beyond the initial contract periods, these expected future cash flows are significantly influenced by the scope and pace of our producer customers’ drilling programs. Once producer customers’ wells are connected to our gathering infrastructure, their likelihood of switching to another provider before the wells are abandoned is reduced due to the significant capital investment required.

The amortization expense related to customer relationships was $353 million, $332 million, and $328 million in 2022, 2021, and 2020, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $357 million.

Transportation and Storage Capacity Contracts

Certain transportation and storage capacity contracts were recognized as intangible assets as part of the Sequent Acquisition. (See Note 3 – Acquisitions.) The amortization expense related to transportation and storage capacity contracts was $158 million in 2022 and $14 million in 2021. The estimated amortization expense for each of the next five succeeding fiscal years is $51 million, $21 million, $10 million, $7 million, and $4 million.

113

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Note 11 – Accrued and Other Current Liabilities

	December 31,
	2022		2021
	(Millions)
Interest on debt	$	274	$	277
Employee costs	218		214
Regulatory liabilities (Note 1)	201		56
Contract liabilities	141		134
Asset retirement obligations (Note 9)	87		75
Operating lease liabilities (Note 13)	25		23
Other, including accrued loss contingencies	324		256
	$	1,270	$	1,035

114

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Note 12 – Debt and Banking Arrangements

Long-Term Debt

	December 31,
	2022		2021
	(Millions)
Transco:
7.08% Debentures due 2026	$	8	$	8
7.25% Debentures due 2026	200		200
7.85% Notes due 2026	1,000		1,000
4% Notes due 2028	400		400
3.25% Notes due 2030	700		700
5.4% Notes due 2041	375		375
4.45% Notes due 2042	400		400
4.6% Notes due 2048	600		600
3.95% Notes due 2050	500		500
Other financing obligation — Atlantic Sunrise	809		830
Other financing obligation — Leidy South	77		72
Other financing obligation — Dalton	252		254
Northwest Pipeline:
7.125% Debentures due 2025	85		85
4% Notes due 2027	500		500
Williams:
3.35% Notes due 2022	—		750
3.6% Notes due 2022	—		1,250
3.7% Notes due 2023	—		850
4.5% Notes due 2023	600		600
4.3% Notes due 2024	1,000		1,000
4.55% Notes due 2024	1,250		1,250
3.9% Notes due 2025	750		750
4% Notes due 2025	750		750
3.75% Notes due 2027	1,450		1,450
3.5% Notes due 2030	1,000		1,000
2.6% Notes due 2031	1,500		1,500
7.5% Debentures due 2031	339		339
7.75% Notes due 2031	252		252
8.75% Notes due 2032	445		445
4.65% Notes due 2032	1,000		—
6.3% Notes due 2040	1,250		1,250
5.8% Notes due 2043	400		400
5.4% Notes due 2044	500		500
5.75% Notes due 2044	650		650
4.9% Notes due 2045	500		500
5.1% Notes due 2045	1,000		1,000
4.85% Notes due 2048	800		800
3.5% Notes due 2051	650		650
5.3% Notes due 2052	750		—
Various — 7.7% to 8.72% Notes due 2022 to 2027	2		2
Unamortized debt issuance costs	(135)		(131)
Net unamortized debt premium (discount)	(55)		(56)
Total long-term debt, including current portion	22,554		23,675
Long-term debt due within one year	(627)		(2,025)
Long-term debt	$	21,927	$	21,650

115

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, and incur additional debt. Default of these agreements could also restrict our ability to make certain distributions or repurchase equity.

The following table presents aggregate minimum maturities of long-term debt and other financing obligations, excluding net unamortized debt premium (discount) and debt issuance costs, for each of the next five years: 

	December 31, 2022
	(Millions)
2023	$	629
2024	2,281
2025	1,619
2026	1,245
2027	1,993

Issuances and retirements

On October 17, 2022, we early retired $850 million of 3.7 percent senior unsecured notes due January 15, 2023.

On August 8, 2022, we issued $1.0 billion of 4.65 percent senior unsecured notes due August 15, 2032, and $750 million of 5.30 percent senior unsecured notes due August 15, 2052.

On May 16, 2022, we early retired $750 million of 3.35 percent senior unsecured notes due August 15, 2022.

On January 18, 2022, we early retired $1.25 billion of 3.6 percent senior unsecured notes due March 15, 2022.

On October 8, 2021, we completed a public offering of $600 million of 2.6 percent senior unsecured notes due 2031. The new 2031 notes are an additional issuance of the $900 million of 2.6 percent senior unsecured notes due 2031 issued on March 2, 2021, and will trade interchangeably with such notes. Also, on October 8, 2021, we completed a public offering of $650 million of 3.5 percent senior unsecured notes due 2051.

We retired $371 million of 7.875 percent senior unsecured notes that matured on September 1, 2021.

On August 16, 2021, we early retired $500 million of 4.0 percent senior unsecured notes due November 15, 2021.

On August 17, 2020, we early retired $600 million of 4.125 percent senior unsecured notes due November 15, 2020.

On May 14, 2020, we completed a public offering of $1 billion of 3.5 percent senior unsecured notes due 2030.

On May 8, 2020, Transco issued $700 million of 3.25 percent senior unsecured notes due 2030 and $500 million of 3.95 percent senior unsecured notes due 2050 to investors in a private debt placement. In the fourth quarter of 2020, Transco filed a registration statement and completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

We retired $1.5 billion of 5.25 percent senior unsecured notes that matured on March 15, 2020.

We retired $14 million of 8.75 percent senior unsecured notes that matured on January 15, 2020.

Other financing obligations

During the construction of the Atlantic Sunrise, Leidy South, and Dalton projects, Transco received funding from co-owners for their proportionate share of construction costs. Amounts received were recorded within

116

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

noncurrent liabilities and the costs associated with construction were capitalized in the Consolidated Balance Sheet. Upon placing these projects into service Transco began utilizing the co-owners’ undivided interest in the assets, including the associated pipeline capacity, and reclassified the funding previously received from its co-owners from noncurrent liabilities to debt. The obligations, which mature in 2038, 2041, and 2052, respectively, require monthly interest and principal payments and bear interest rates of approximately 9 percent, 13 percent, and 9 percent, respectively.

Credit Facility

	December 31, 2022
	Stated Capacity		Outstanding
	(Millions)
Long-term credit facility (1)	$	3,750	$	—
Letters of credit under certain bilateral bank agreements			30

________________

(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.

Revolving credit facility

In October 2021, we along with Transco and Northwest Pipeline, the lenders named therein, and an administrative agent entered into an amended and restated credit agreement (Credit Agreement) that reduced aggregate commitments available from $4.5 billion to $3.75 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. The Credit Agreement was effective on October 8, 2021. The maturity date of the credit facility is October 8, 2026. However, the co-borrowers may request up to two extensions of the maturity date each for an additional one-year period to allow a maturity date as late as October 8, 2028, under certain circumstances. The Credit Agreement allows for swing line loans up to an aggregate of $200 million, subject to available capacity under the credit facility, and letters of credit commitments of $500 million. Transco and Northwest Pipeline are each able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers.

The Credit Agreement contains the following terms and conditions:

•Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets in certain circumstances, make certain distributions during an event of default, and each borrower and each borrower’s respective material subsidiaries’ ability to enter into certain restrictive agreements.

•If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for the respective borrowers and accelerate the maturity of the loans of the defaulting borrower under the credit facility and exercise other rights and remedies.

•Other than swing line loans, each time funds are borrowed, the applicable borrower may choose from two methods of calculating interest: a fluctuating base rate equal to an alternative base rate as defined in the Credit Agreement plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin is determined by reference to a pricing schedule based on the applicable borrower’s senior unsecured long-term debt ratings and the commitment fee is determined by reference to a pricing schedule based on Williams’ senior unsecured long-term debt ratings. The Credit Agreement also includes customary provisions to provide for replacement of LIBOR with an alternative benchmark rate when LIBOR ceases to be available.

117

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Significant financial covenants under the Credit Agreement require the ratio of debt to EBITDA (earnings before interest, taxes, depreciation, and amortization), each as defined in the Credit Agreement, to be no greater than 5.0 to 1.0, except that for any fiscal quarter in which the funding of the purchase price for an acquisition (whether effectuated as one or a series of related transactions) with an aggregate purchase price of $25 million or more has been effected, and the following two fiscal quarters (in each case subject to certain limitations), the ratio of debt to EBITDA is to be no greater than 5.5 to 1.

The ratio of debt to capitalization (defined as net worth plus debt), each as defined in the Credit Agreement, must be no greater than 65 percent for each of Transco and Northwest Pipeline.

At December 31, 2022, we are in compliance with these covenants.

Commercial Paper Program

In 2018, we entered into a $4 billion commercial paper program that has been reduced to $3.5 billion in connection with the October 2021 Credit Agreement. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. The net proceeds of issuances of the commercial paper notes are expected to be used to fund planned capital expenditures and for other general corporate purposes. At December 31, 2022, $350 million of commercial paper was outstanding at a weighted-average interest rate of 4.8 percent. We had no commercial paper outstanding at December 31, 2021.

Cash Payments for Interest (Net of Amounts Capitalized)

Cash payments for interest (net of amounts capitalized) were $1.117 billion in 2022, $1.137 billion in 2021, and $1.149 billion in 2020.

118

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Note 13 – Leases

We are a lessee through noncancellable lease agreements for property and equipment consisting primarily of buildings, land, vehicles, and equipment used in both our operations and administrative functions.

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Lease Cost:
Operating lease cost	$	34	$	35	$	37
Variable lease cost	26		15		19
Sublease income	—		(1)		(1)
Total lease cost	$	60	$	49	$	55
Cash paid for operating lease liabilities	$	33	$	35	$	30

	December 31,
	2022		2021
	(Millions)
Other Information:
Right-of-use asset (included in Regulatory assets, deferred charges, and other)	$	162	$	159
Operating lease liabilities:
Current (included in Accrued and other current liabilities)	$	25	$	23
Noncurrent (included in Regulatory liabilities, deferred income, and other)	$	148	$	141
Weighted-average remaining lease term – operating leases (years)	13		13
Weighted-average discount rate – operating leases	4.62%		4.56%

At December 31, 2022, the following table represents our operating lease maturities, including renewal provisions that we have assessed as being reasonably certain of exercise, for each of the years ended December 31:

	(Millions)
2023	$	31
2024	26
2025	20
2026	20
2027	19
Thereafter	122
Total future lease payments	238
Less: Amount representing interest	65
Total obligations under operating leases	$	173

We are the lessor to certain lease agreements for office space in our headquarters building, which are insignificant to our financial statements.

Note 14 – Equity-Based Compensation

Williams’ Plan Information

The Williams Companies, Inc. 2007 Incentive Plan (the Plan) provides common-stock-based awards to both employees and nonmanagement directors. To date, 50 million new shares have been authorized for making awards under the Plan, including 10 million shares added on April 28, 2020. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. At December 31, 2022, 25 million

119

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 15 million shares were available for future grants.

Additionally, up to 5.2 million new shares of our common stock have been authorized to date to be available for sale under our Employee Stock Purchase Plan (ESPP), including 1.6 million shares added on April 28, 2020. Employees purchased 242 thousand shares at a weighted-average price of $24.57 per share during 2022. Approximately 1.2 million shares were available for purchase under the ESPP at December 31, 2022.

We recognize compensation expense on employee stock-based awards on a straight-line basis; forfeitures are recognized when they occur. Operating and maintenance expenses and Selling, general, and administrative expenses in our Consolidated Statement of Income include equity-based compensation expense in 2022, 2021, and 2020 of $73 million, $81 million, and $52 million, respectively. Income tax benefit recognized related to the stock-based compensation expense in 2022, 2021, and 2020 was $18 million, $20 million, and $13 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2022, was $63 million, all of which related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.7 years.

Nonvested Restricted Stock Units

At December 31, 2022 and 2021, we had restricted stock units outstanding, including performance-based shares, of 6.9 million shares and 7.3 million shares, respectively, with a weighted-average fair value of $23.63 and $22.35, respectively. Restricted stock units generally vest after three years. Performance-based grants may vest at a range from zero percent to 200 percent of the original shares granted based on performance against a target. At December 31, 2022, there were 2.6 million performance-based shares outstanding.

Stock Options

There were no stock options granted in 2022, 2021, or 2020. At December 31, 2022, we had 2.8 million stock options that were both outstanding and exercisable, with a weighted-average exercise price of $34.32. The weighted-average remaining contractual life for stock options that were both outstanding and exercisable at December 31, 2022, was 2.8 years. Cash received for the exercise of stock options in 2022 was $49 million, and the related income tax benefit recognized in 2022 was $2 million.

120

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk

The following table presents, by level within the fair value hierarchy, certain of our significant financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, accounts payable, and commercial paper approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.

					Fair Value Measurements Using
	Carrying Amount		Fair Value		Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at December 31, 2022:
Measured on a recurring basis:
ARO Trust investments	$	230	$	230	$	230	$	—	$	—
Commodity derivative assets (1)	166		166		20		132		14
Commodity derivative liabilities (1)	(810)		(810)		(22)		(718)		(70)
Other financial assets (liabilities) - net	(5)		(5)		—		(5)		—
Additional disclosures:
Long-term debt, including current portion	(22,554)		(21,569)		—		(21,569)		—
Guarantees	(38)		(25)		—		(9)		(16)
Assets (liabilities) at December 31, 2021:
Measured on a recurring basis:
ARO Trust investments	$	260	$	260	$	260	$	—	$	—
Commodity derivative assets (2)	84		84		2		81		1
Commodity derivative liabilities (2)	(488)		(488)		(69)		(403)		(16)
Other financial assets (liabilities) - net	(7)		(7)		—		(7)		—
Additional disclosures:
Long-term debt, including current portion	(23,675)		(27,768)		—		(27,768)		—
Guarantees	(39)		(26)		—		(10)		(16)

(1)Net commodity derivative assets and liabilities exclude $202 million of net cash collateral in Level 1.

(2)Net commodity derivative assets and liabilities exclude $296 million of net cash collateral in Level 1.

Fair Value Methods

We use the following methods and assumptions in estimating the fair value of our financial instruments:

Assets measured at fair value on a recurring basis

ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust that is specifically designated to fund future ARO’s. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market and is reported in Regulatory assets, deferred charges, and other in our Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.

121

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Commodity derivatives: Commodity derivatives include exchange-traded contracts and OTC contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. We also have other derivatives related to asset management agreements and other contracts that require physical delivery. Derivatives classified as Level 1 are valued using New York Mercantile Exchange (NYMEX) futures prices. Derivatives classified as Level 2 are valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers. Derivatives classified as Level 3 are valued using a combination of observable and unobservable inputs. The fair value amounts are presented on a net basis and reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements and cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Commodity derivative assets are reported in Derivative assets and Regulatory assets, deferred charges, and other in our Consolidated Balance Sheet. Commodity derivative liabilities are reported in Derivative liabilities and Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet. Changes in the fair value of our derivative assets and liabilities are recorded in Net gain (loss) on commodity derivatives and Net processing commodity expenses in our Consolidated Statement of Income. See Note 16 – Derivatives for additional information on our derivatives.

The following table presents a reconciliation of changes in fair value of our net commodity derivatives classified as Level 3 in the fair value hierarchy.

	Year Ended December 31,
	2022		2021
	(Millions)
Balance at beginning of period	$	(15)	$	(2)
Gains (losses) included in our Consolidated Statement of Income	(31)		(62)
Purchases, issuances, and settlements	(5)		13
Acquired derivatives (Note 3)	—		24
Transfers into Level 3	(24)		—
Transfers out of Level 3	19		12
Balance at end of period	$	(56)	$	(15)

A substantial portion of the carrying value of our Level 3 derivatives at December 31, 2022, relates to a long-term physical natural gas purchase contract associated with an ongoing pipeline expansion project. The valuation of this contract reflects the extrapolation of forward natural gas prices for periods beyond observable price curves, which is considered a significant unobservable input.

Additional fair value disclosures

Long-term debt, including current portion: The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair values of the financing obligations associated with our Dalton, Leidy South, and Atlantic Sunrise projects, which are included within long-term debt, were determined using an income approach (see Note 12 – Debt and Banking Arrangements).

Guarantees: Guarantees primarily consist of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation that extends through 2042. Guarantees also include an indemnification related to a disposed operation.

To estimate the fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying

122

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

value of the WilTel guarantee is reported in Accrued and other current liabilities in our Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $24 million at December 31, 2022. Our exposure declines systematically through the remaining term of WilTel’s obligation.

The fair value of the guarantee associated with the indemnification related to a disposed operation was estimated using an income approach that considered probability-weighted scenarios of potential levels of future performance. The terms of the indemnification do not limit the maximum potential future payments associated with the guarantee. The carrying value of this guarantee is reported in Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet.

We are required by our revolving credit agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.

Nonrecurring fair value measurements

During the first quarter of 2020, we observed a significant decline in the publicly traded price of our common stock on the New York Stock Exchange, which declined 40 percent during the quarter, including a 26 percent decline in the month of March. These changes were generally attributed to macroeconomic and geopolitical conditions, including significant declines in crude oil prices driven by both surplus supply and a decrease in demand caused by the coronavirus pandemic. As a result of these conditions, we performed an interim assessment of the goodwill associated with our Northeast G&P reporting unit as of March 31, 2020.

The assessment considered the total fair value of the businesses within the Northeast G&P reporting unit, which was determined using income and market approaches. We utilized internally developed industry weighted-average discount rates and estimates of valuation multiples of comparable publicly traded gathering and processing companies. In assessing the fair value as of the March 31, 2020, measurement date, we were required to consider recent publicly available indications of value, which included lower observed publicly traded EBITDA market multiples as compared with recent history and significantly higher industry weighted-average discount rates. The fair value of the reporting unit was further reconciled to our estimated total enterprise value as of March 31, 2020, which considered observable valuation multiples of comparable publicly traded companies applied to each distinct business including the Northeast G&P reporting unit. This assessment indicated that the estimated fair value of the Northeast G&P reporting unit was below its carrying value, including goodwill. As a result of this Level 3 measurement, we recognized a full impairment charge of $187 million as of March 31, 2020, in Impairment of goodwill in our Consolidated Statement of Income. Our partner’s $65 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in our Consolidated Statement of Income.

123

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

The following table presents impairments of assets and equity-method investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy, except as specifically noted.

					Impairments
					Year Ended December 31,
	Segment	Date of Measurement	Fair Value		2022		2021		2020
			(Millions)
Impairment of certain assets:
Certain capitalized project costs (1)	Transmission & Gulf of Mexico	June 30, 2021	$	1			$	2
Certain capitalized project costs (1)	Transmission & Gulf of Mexico	December 31, 2020	42						$	170
Certain gathering assets (2)	Northeast G&P	December 31, 2020	5						12
Impairment of certain assets					$	—	$	2	$	182
Impairment of equity-method investments:
RMM (3)	West	December 31, 2020	$	421					$	108
RMM (4)	West	March 31, 2020	557						243
Brazos Permian II (4)	West	March 31, 2020	—						193
BRMH (5)	Northeast G&P	March 31, 2020	191						229
Appalachia Midstream Investments (5)	Northeast G&P	March 31, 2020	2,700						127
Aux Sable (5)	Northeast G&P	March 31, 2020	7						39
Laurel Mountain (5)	Northeast G&P	March 31, 2020	236						10
Discovery (5)	Transmission & Gulf of Mexico	March 31, 2020	367						97
Impairment of equity-method investments					$	—	$	—	$	1,046

______________

(1)Relates to capitalized project development costs for the Northeast Supply Enhancement project. Approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection have been denied and we have not refiled at this time. Beginning in May 2020, we discontinued capitalization of costs related to this project. Considering that the customer precedent agreements and FERC certificate for the project remain in effect, we had previously concluded that the probability of completing the project was sufficient to not require impairment. However, developments in the political and regulatory environments caused us to slightly lower that assessed probability such that the capitalized project costs required impairment. The estimated fair value of the materials within the capitalized project costs at December 31, 2020 considered other internal uses and salvage values for the Property, plant, and equipment – net. The remaining capitalized costs were determined to have no fair value. The estimated fair value of certain capitalized project costs at June 30, 2021, was determined by a market approach, which incorporated an indication of interest by a third-party.

(2)Relates to a gathering system in the Marcellus Shale region, that was sold in 2021. The estimated fair value of the Property, plant, and equipment – net and Intangible assets – net of accumulated amortization was determined using a market approach, which incorporated an indication of interest by a third party. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy.

124

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

(3)During the fourth quarter of 2020, RMM renegotiated service contracts with a significant customer in connection with the customer’s Chapter 11 bankruptcy proceedings. The renegotiated contracts result in lower service rates and lower projected future cash flows. As a result, we evaluated this investment for other-than-temporary impairment. The fair value was measured using an income approach. We utilized a discount rate of 18 percent in our analysis.

(4)Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The fair value was measured using an income approach. Both investees operate in primarily oil-driven basins where significant expected reductions in producer activities led to reduced estimates of expected future cash flows. Our fair value estimates also reflected discount rates of approximately 17 percent for these investments. We also considered any debt held at the investee level, and its impact to fair value. The industry weighted-average discount rates utilized were significantly influenced by the market declines previously discussed.

(5)Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The impairments within our Northeast G&P segment are primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices which historically trend with crude oil prices. The fair values of our investments in BRMH and Aux Sable Liquid Products LP (Aux Sable) were estimated using a market approach, reflecting valuation multiples ranging from 5.0x to 6.2x EBITDA (weighted-average 6.0x). The fair values of the other investments, including gathering systems that are part of Appalachia Midstream Investments, were estimated using an income approach, with discount rates ranging from 9.7 percent to 13.5 percent (weighted-average 12.6 percent). We also considered any debt held at the investee level, and its impact to fair value. The assumed valuation multiples and industry weighted-average discount rates utilized were both significantly influenced by the market declines previously discussed.

Concentration of Credit Risk

Accounts receivable

The following table summarizes concentration of receivables, net of allowances:

	December 31,
	2022		2021
	(Millions)
NGLs, natural gas, and related products and services	$	505	$	486
Regulated interstate natural gas transportation and storage	311		274
Marketing of natural gas and NGLs	858		609
Upstream activities	97		82
Accounts Receivable related to revenues from contracts with customers	1,771		1,451
Receivables from derivatives	889		462
Other accounts receivable	63		65
Trade accounts and other receivables - net	$	2,723	$	1,978

Customers include producers, distribution companies, industrial users, gas marketers, and pipelines primarily located in the continental United States. As a general policy, collateral is not required for receivables with the exception of the marketing receivables discussed below. Customers’ financial condition and credit worthiness are evaluated regularly and, based upon this evaluation, we may obtain collateral to support receivables.

We use established credit policies to determine and monitor the creditworthiness of gas marketing and trading counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade

125

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

financial institution, but may also include U.S. government securities. We also utilize netting agreements whenever possible to mitigate exposure to gas marketing and trading counterparty credit risk. When more than one derivative transaction with the same counterparty is outstanding and a legally enforceable netting agreement exists with that counterparty, the “net” mark-to-market exposure represents a reasonable measure of our credit risk with that counterparty.

Note 16 – Derivatives

Commodity-Related Derivatives

We are exposed to commodity price risk. To manage this volatility, we use various contracts in our marketing and trading activities that generally meet the definition of derivatives. Derivative positions are monitored using techniques including, but not limited to, value at risk. Derivative instruments are recognized at fair value in our Consolidated Balance Sheet as either assets or liabilities and are presented on a net basis by counterparty, net of margin deposits. See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk for additional fair value information. In our Consolidated Statement of Cash Flows, any cash impacts of settled commodity-related derivatives are recorded as operating activities.

We enter into commodity-related derivatives to economically hedge exposures to natural gas, NGLs, and crude oil and retain exposure to price changes that can, in a volatile energy market, be material and can adversely affect our results of operations.

At December 31, 2022, the notional volume of the net long (short) positions for our commodity-related derivative contracts were as follows:

	Commodity	Unit of Measure	Net Long (Short) Position
Index Risk	Natural Gas	MMBtu	745,415,032
Central Hub Risk - Henry Hub	Natural Gas	MMBtu	(46,154,200)
Basis Risk	Natural Gas	MMBtu	(50,737,802)
Central Hub Risk - Mont Belvieu	Natural Gas Liquids	Barrels	35,548
Basis Risk	Natural Gas Liquids	Barrels	(3,880,364)
Central Hub Risk - WTI	Crude Oil	Barrels	(123,250)

Derivative Financial Statement Presentation

The fair value of commodity-related derivatives, which are not designated as hedging instruments for accounting purposes, was reflected as follows:

	December 31, 2022				December 31, 2021
Derivative Category	Assets		(Liabilities)		Assets		(Liabilities)
	(Millions)
Current	$	1,099	$	(1,278)	$	619	$	(760)
Noncurrent	269		(734)		166		(429)
Total derivatives	$	1,368	$	(2,012)	$	785	$	(1,189)
Counterparty and collateral netting offset	(1,034)		1,236		(476)		772
Amounts recognized in our Consolidated Balance Sheet	$	334	$	(776)	$	309	$	(417)

126

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

The pre-tax effects of commodity-related derivative instruments in Net gain (loss) on commodity derivatives reflected within Total revenues and Net processing commodity expenses in our Consolidated Statement of Income were as follows:

	Gain (Loss)
	Year Ended December 31,
	2022		2021		2020
	(Millions)
Realized commodity-related derivatives designated as hedging instruments	$	—	$	(55)	$	(2)
Realized commodity-related derivatives not designated as hedging instruments	(91)		16		(3)
Unrealized commodity-related derivatives not designated as hedging instruments	(296)		(109)		—
Net gain (loss) on commodity derivatives	$	(387)	$	(148)	$	(5)
Realized commodity-related derivatives not designated as hedging instruments in Net processing commodity expenses	$	16	$	2	$	1
Unrealized commodity-related derivatives not designated as hedging instruments in Net processing commodity expenses	$	47	$	—	$	—

Contingent Features

Generally, collateral may be provided by a parent guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are offset against fair value amounts recognized for derivatives executed with the same counterparty.

We have specific trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, we would need to post collateral to continue transacting business with these counterparties. At December 31, 2022, the contractually required collateral in the event of a credit rating downgrade to non-investment grade status was $13 million.

We maintain accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, we may be required to deposit cash into these accounts. At December 31, 2022, and 2021, net cash collateral held on deposit in broker margin accounts was $202 million and $296 million, respectively.

Note 17 – Contingent Liabilities and Commitments

Alaska Refinery Contamination Litigation

We are involved in litigation arising from our ownership and operation of the North Pole Refinery in North Pole, Alaska, from 1980 until 2004, through our wholly owned subsidiaries Williams Alaska Petroleum Inc. (WAPI) and MAPCO Inc. We sold the refinery to Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., in 2004. The litigation involves three cases, with filing dates ranging from 2010 to 2014. The actions primarily arise from sulfolane contamination allegedly emanating from the refinery. A putative class action lawsuit was filed by James West in 2010 naming us, WAPI, and FHRA as defendants. We and FHRA filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA settled the claim with James West. Certain claims by FHRA against us were resolved by the Alaska Supreme Court in our favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane were remanded to the Alaska Superior

127

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Court. The State of Alaska filed its action in March 2014, seeking damages. The City of North Pole (North Pole) filed its lawsuit in November 2014, seeking past and future damages, as well as punitive damages. Both we and WAPI asserted counterclaims against the State of Alaska and North Pole, and cross-claims against FHRA. FHRA has also filed cross-claims against us.

The underlying factual basis and claims in the cases are similar and may duplicate exposure. As such, in February 2017, the three cases were consolidated into one action in state court containing the remaining claims from the James West case and those of the State of Alaska and North Pole. The State of Alaska later announced the discovery of additional contaminants per- and polyfluoralkyl (PFOS and PFOA) offsite of the refinery, and the court permitted the State of Alaska to amend its complaint to add a claim for offsite PFOS/PFOA contamination. The court subsequently remanded the offsite PFOS/PFOA claims to the Alaska Department of Environmental Conservation for investigation and stayed the claims pending their potential resolution at the administrative agency. Several trial dates encompassing all three cases have been scheduled and stricken. In the summer of 2019, the court deconsolidated the cases for purposes of trial. A bench trial on all claims except North Pole’s claims began in October 2019.

In January 2020, the Alaska Superior Court issued its Memorandum of Decision finding in favor of the State of Alaska and FHRA, with the total incurred and potential future damages estimated to be $86 million. The court found that FHRA is not entitled to contractual indemnification from us because FHRA contributed to the sulfolane contamination. On March 23, 2020, the court entered final judgment in the case. Filing deadlines were stayed until May 1, 2020. However, on April 21, 2020, we filed a Notice of Appeal. We also filed post-judgment motions including a Motion for New Trial and a Motion to Alter or Amend the Judgment. These post-trial motions were resolved with the court’s denial of the last motion on June 11, 2020. Our Statement of Points on Appeal was filed on July 13, 2020. On June 22, 2020, the court stayed the North Pole’s case pending resolution of the appeal in the State of Alaska and FHRA case. On December 23, 2020, we filed our opening brief on appeal. Oral argument was held on December 15, 2021. We have recorded an accrued liability in the amount of our estimate of the probable loss. It is reasonably possible that we may not be successful on appeal and could ultimately pay up to the amount of judgment.

Royalty Matters

Certain of our customers, including Chesapeake Energy Corporation (Chesapeake), have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases filed in Pennsylvania based on allegations that we improperly participated with Chesapeake in causing the alleged royalty underpayments. We believe that the claims asserted are subject to indemnity obligations owed to us by Chesapeake. Chesapeake has reached a settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement applies to both Chesapeake and us. The settlement does not require any contribution from us. On August 23, 2021, the court approved the settlement, but two objectors filed an appeal with the United States Court of Appeals for the Fifth Circuit.

Litigation Against Energy Transfer and Related Parties

On April 6, 2016, we filed suit in Delaware Chancery Court against Energy Transfer Equity, L.P. (Energy Transfer) and LE GP, LLC (the general partner for Energy Transfer) alleging willful and material breaches of the Agreement and Plan of Merger (ETE Merger Agreement) with Energy Transfer resulting from the private offering by Energy Transfer on March 8, 2016, of Series A Convertible Preferred Units (Special Offering) to certain Energy Transfer insiders and other accredited investors. The suit seeks, among other things, an injunction ordering the defendants to unwind the Special Offering and to specifically perform their obligations under the ETE Merger Agreement. On April 19, 2016, we filed an amended complaint seeking the same relief. On May 3, 2016, Energy Transfer and LE GP, LLC filed an answer and counterclaims.

On May 13, 2016, we filed a separate complaint in Delaware Chancery Court against Energy Transfer, LE GP, LLC and the other Energy Transfer affiliates that are parties to the ETE Merger Agreement, alleging material

128

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

breaches of the ETE Merger Agreement for failing to cooperate and use necessary efforts to obtain a tax opinion required under the ETE Merger Agreement (Tax Opinion) and for otherwise failing to use necessary efforts to consummate the merger under the ETE Merger Agreement wherein we would be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger). The suit sought, among other things, a declaratory judgment and injunction preventing Energy Transfer from terminating or otherwise avoiding its obligations under the ETE Merger Agreement due to any failure to obtain the Tax Opinion.

The Court of Chancery coordinated the Special Offering and Tax Opinion suits. On May 20, 2016, the Energy Transfer defendants filed amended affirmative defenses and verified counterclaims in the Special Offering and Tax Opinion suits, alleging certain breaches of the ETE Merger Agreement by us and seeking, among other things, a declaration that we were not entitled to specific performance, that Energy Transfer could terminate the ETC Merger, and that Energy Transfer is entitled to a $1.48 billion termination fee. On June 24, 2016, following a two-day trial, the court issued a Memorandum Opinion and Order denying our requested relief in the Tax Opinion suit. The court did not rule on the substance of our claims related to the Special Offering or on the substance of Energy Transfer’s counterclaims. On June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017.

On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the ETE Merger Agreement by defendants. On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the ETE Merger Agreement. On December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument, which the Court of Chancery denied on April 16, 2018. Trial was held May 10 through May 17, 2021. On December 29, 2021, the court entered judgment in our favor in the amount of $410 million, plus interest at the contractual rate, and our reasonable attorneys’ fees and expenses. On September 21, 2022, the court entered a final order and judgment awarding us the termination fee, attorney’s fees, expenses, and interest in the amount of $602 million plus additional interest starting September 17, 2022. Energy Transfer has appealed to the Delaware Supreme Court.

Environmental Matters

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of December 31, 2022, we have accrued liabilities totaling $40 million for these matters, as discussed below. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At December 31, 2022, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

The EPA and various state regulatory agencies routinely propose and promulgate new rules and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine maximum achievable control technology, reviews and updates to the National Ambient Air Quality Standards, and rules for new and existing source performance standards for volatile

129

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

organic compound and methane. We continuously monitor these regulatory changes and how they may impact our operations. Implementation of new or modified regulations may result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in our Consolidated Balance Sheet for both new and existing facilities in affected areas; however, due to regulatory uncertainty on final rule content and applicability timeframes, we are unable to reasonably estimate the cost of these regulatory impacts at this time.

Continuing operations

Our interstate gas pipelines are involved in remediation and monitoring activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At December 31, 2022, we have accrued liabilities of $13 million for these costs and expect to recover approximately $4 million through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 2022, we have accrued liabilities totaling $10 million for these costs.

Former operations

We have potential obligations in connection with assets and businesses we no longer operate. These potential obligations include remediation activities at the direction of federal and state environmental authorities and the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described below.

•Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations;

•Former petroleum products and natural gas pipelines;

•Former petroleum refining facilities;

•Former exploration and production and mining operations;

•Former electricity and natural gas marketing and trading operations.

At December 31, 2022, we have accrued environmental liabilities of $17 million related to these matters.

Other Divestiture Indemnifications

Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided.

At December 31, 2022, other than as previously disclosed, we are not aware of any material claims against us involving the above-described indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made.

130

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

In addition to the foregoing, various other proceedings are pending against us that are incidental to our operations, none of which are expected to be material to our expected future annual results of operations, liquidity, and financial position.

Summary

We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties.

Commitments

Commitments for construction and acquisition of property, plant, and equipment are approximately $439 million at December 31, 2022.

Commitments for Gas & NGL Marketing Services pipeline transportation capacity and storage capacity are approximately $546 million at December 31, 2022.

Note 18 – Segment Disclosures

Our reportable segments are Transmission & Gulf of Mexico, Northeast G&P, West, and Gas & NGL Marketing Services. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

Performance Measurement

We evaluate segment operating performance based upon Modified EBITDA. This measure represents the basis of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments. Intersegment Service revenues primarily represent transportation services provided to our marketing business and gathering services provided to our oil and gas properties. Intersegment Product sales primarily represent the sale of natural gas and NGLs from our natural gas processing plants and our oil and gas properties to our marketing business.

We define Modified EBITDA as follows:

•Net income (loss) before:

◦Provision (benefit) for income taxes;

◦Interest incurred, net of interest capitalized;

◦Equity earnings (losses);

◦Impairment of equity-method investments;

◦Other investing income (loss) – net;

◦Impairment of goodwill;

◦Depreciation and amortization expenses;

◦Accretion expense associated with asset retirement obligations for nonregulated operations.

•This measure is further adjusted to include our proportionate share (based on ownership interest) of Modified EBITDA from our equity-method investments calculated consistently with the definition described above.

131

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in our Consolidated Statement of Income:

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Modified EBITDA by segment:
Transmission & Gulf of Mexico	$	2,674	$	2,621	$	2,379
Northeast G&P	1,796		1,712		1,489
West	1,211		961		947
Gas & NGL Marketing Services (1)	(40)		22		51
Other	434		178		(15)
	6,075		5,494		4,851
Accretion expense associated with asset retirement obligations for nonregulated operations	(51)		(45)		(35)
Depreciation and amortization expenses	(2,009)		(1,842)		(1,721)
Impairment of goodwill	—		—		(187)
Equity earnings (losses)	637		608		328
Impairment of equity-method investments	—		—		(1,046)
Other investing income (loss) – net	16		7		8
Proportional Modified EBITDA of equity-method investments	(979)		(970)		(749)
Interest expense	(1,147)		(1,179)		(1,172)
(Provision) benefit for income taxes	(425)		(511)		(79)
Net income (loss)	$	2,117	$	1,562	$	198

____________

(1)    Modified EBITDA for 2022, 2021, and 2020, includes charges of $161 million, $15 million, and $17 million respectively, associated with lower of cost or net realizable value adjustments to our inventory. These charges are reflected in Product Sales or Product costs in our Consolidated Statement of Income (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies). Net unrealized commodity-related derivatives gains of $47 million in 2022 and $0 in 2021 and 2020 are reflected in Net processing commodity expenses.

132

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Income and Other financial information:

	Transmission & Gulf of Mexico		Northeast G&P		West		Gas & NGL Marketing Services (1)		Other		Eliminations		Total
	(Millions)
2022
Segment revenues:
Service revenues
External	$	3,461	$	1,613	$	1,443	$	3	$	16	$	—	$	6,536
Internal	118		41		99		—		8		(266)		—
Total service revenues	3,579		1,654		1,542		3		24		(266)		6,536
Total service revenues – commodity consideration	64		14		182		—		—		—		260
Product sales
External	228		28		145		4,052		103		—		4,556
Internal	176		106		696		(518)		603		(1,063)		—
Total product sales	404		134		841		3,534		706		(1,063)		4,556
Net gain (loss) on commodity derivatives
Realized	—		—		(4)		17		(104)		—		(91)
Unrealized	—		—		—		(321)		25		—		(296)
Total net gain (loss) on commodity derivatives (2)	—		—		(4)		(304)		(79)		—		(387)
Total revenues	$	4,047	$	1,802	$	2,561	$	3,233	$	651	$	(1,329)	$	10,965
Other financial information:
Additions to long-lived assets	$	1,420	$	261	$	1,507	$	4	$	406	$	—	$	3,598
Proportional Modified EBITDA of equity-method investments	193		654		132		—		—		—		979
2021
Segment revenues:
Service revenues
External	$	3,310	$	1,490	$	1,178	$	3	$	20	$	—	$	6,001
Internal	75		38		70		—		12		(195)		—
Total service revenues	3,385		1,528		1,248		3		32		(195)		6,001
Total service revenues – commodity consideration	52		7		179		—		—		—		238
Product sales
External	231		13		60		4,094		138		—		4,536
Internal	118		86		583		198		195		(1,180)		—
Total product sales	349		99		643		4,292		333		(1,180)		4,536
Net gain (loss) on commodity derivatives
Realized	—		—		(44)		25		(20)		—		(39)
Unrealized	—		—		—		(109)		—		—		(109)
Total net gain (loss) on commodity derivatives (2)	—		—		(44)		(84)		(20)		—		(148)
Total revenues	$	3,786	$	1,634	$	2,026	$	4,211	$	345	$	(1,375)	$	10,627
Other financial information:
Additions to long-lived assets	$	861	$	164	$	209	$	1	$	620	$	—	$	1,855
Proportional Modified EBITDA of equity-method investments	183		682		105		—		—		—		970

133

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

	Transmission & Gulf of Mexico		Northeast G&P		West		Gas & NGL Marketing Services (1)		Other		Eliminations		Total
	(Millions)
2020
Segment revenues:
Service revenues
External	$	3,207	$	1,416	$	1,248	$	32	$	21	$	—	$	5,924
Internal	50		49		24		—		13		(136)		—
Total service revenues	3,257		1,465		1,272		32		34		(136)		5,924
Total service revenues – commodity consideration	21		7		101		—		—		—		129
Product sales
External	144		16		20		1,491		—		—		1,671
Internal	47		41		132		111		—		(331)		—
Total product sales	191		57		152		1,602		—		(331)		1,671
Net gain (loss) on commodity derivatives
Realized	—		—		(2)		(3)		—		—		(5)
Unrealized	—		—		—		—		—		—		—
Total net gain (loss) on commodity derivatives (2)	—		—		(2)		(3)		—		—		(5)
Total revenues	$	3,469	$	1,529	$	1,523	$	1,631	$	34	$	(467)	$	7,719
Other financial information:
Additions to long-lived assets	$	706	$	137	$	318	$	—	$	122	$	—	$	1,283
Proportional Modified EBITDA of equity-method investments	166		473		110		—		—		—		749

______________

(1)    See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.

(2)    We record transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue.

Segment assets include Investments, Property, plant, and equipment – net, and Intangible assets – net of accumulated amortization. The following table reflects segment assets and equity-method investments by reportable segments:

	Segment Assets				Equity-Method Investments
	December 31, 2022		December 31, 2021		December 31, 2022		December 31, 2021
	(Millions)
Transmission & Gulf of Mexico	$	17,795	$	17,142	$	629	$	602
Northeast G&P	13,539		13,861		3,566		3,681
West	10,710		9,698		843		838
Gas & NGL Marketing Services	130		294		—		—
Other	1,143		792		10		—
Total	43,317		41,787		$	5,048	$	5,121
Total current assets	3,797		4,549
Regulatory assets, deferred charges, and other	1,319		1,276
Total assets	$	48,433	$	47,612

134

The Williams Companies, Inc.

Notes to Consolidated Financial Statements – (Continued)

Note 19 – Subsequent Events

Quarterly Dividends to Common Stockholders

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

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 (MountainWest Acquisition), for $1.08 billion of cash funded with available sources of short-term liquidity 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. Due to the timing, the initial purchase price accounting for the transaction was not yet complete at the time of filing.

135

The Williams Companies, Inc.

Schedule II — Valuation and Qualifying Accounts

			Additions
	Beginning Balance		Charged (Credited) To Costs and Expenses		Other		Deductions		Ending Balance
	(Millions)
2022
Deferred tax asset valuation allowance (1)	$	297	$	(97)	$	—	$	—	$	200
2021
Deferred tax asset valuation allowance (1)	325		(28)		—		—		297
2020
Deferred tax asset valuation allowance (1)	319		6		—		—		325

__________

(1)    Deducted from related assets.

136

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Exchange Act) (Disclosure Controls) or our internal control over financial reporting (Internal Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and Internal Controls will be modified as systems change and conditions warrant.

Evaluation of Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There have been no changes during the fourth quarter of 2022 that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.

Management’s Annual Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a - 15(f) and 15d - 15(f) under the Exchange Act). Our internal control over financial reporting is designed to provide reasonable assurance to our management and board of directors regarding the preparation and fair presentation of financial statements in accordance with accounting principles generally accepted in the United States. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and board of directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

All internal control systems, no matter how well designed, have inherent limitations including the possibility of human error and the circumvention or overriding of controls. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

137

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting at December 31, 2022, based on the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessment, we concluded that, at December 31, 2022, our internal control over financial reporting was effective.

Ernst & Young LLP, our independent registered public accounting firm, has audited our internal control over financial reporting, as stated in their report which is included in this Annual Report on Form 10-K.

138

Report of Independent Registered Public Accounting Firm

The Stockholders and the Board of Directors of

The Williams Companies, Inc.

Opinion on Internal Control Over Financial Reporting

We have audited The Williams Companies, Inc.’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, The Williams Companies, Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheet of the Company as of December 31, 2022 and 2021, the related consolidated statements of income, comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2022, and the related notes and the financial statement schedule listed in the index at Item 15(a) and our report dated February 27, 2023 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 27, 2023

139

Item 9B. Other Information

None.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information regarding our directors and nominees for director required by Item 401 of Regulation S-K will be presented under the heading “Corporate Governance and Board Matters” in our definitive proxy statement prepared for the solicitation of proxies in connection with our Annual Meeting of Stockholders to be held April 25, 2023, which shall be filed no later than March 16, 2023 (Proxy Statement), which information is incorporated by reference herein.

Information regarding our executive officers required by Item 401 of Regulation S-K is presented at the end of Part I herein and captioned “Information About Our Executive Officers,” as permitted by General Instruction G(3) and the Instruction to Item 401 of Regulation S-K.

Information required by paragraphs (c)(3), (d)(4) and (d)(5) of Item 407 of Regulation S-K will be included under the heading “Questions and Answers About the Annual Meeting and Voting” and “Corporate Governance and Board Matters” in our Proxy Statement, which information is incorporated by reference herein.

Our Corporate Governance Guidelines, the charters for each of our board committees, and our Code of Business Conduct applicable to all employees, including our Chief Executive Officer, Chief Financial Officer, and Chief Accounting Officer, or persons performing similar functions, are available on our Internet website at www.williams.com. We will provide, free of charge, a copy of our Code of Business Conduct or any of our other corporate documents listed above upon written request to our Corporate Secretary at Williams, One Williams Center, Suite 4700, Tulsa, Oklahoma 74172. We intend to disclose any amendments to or waivers, in each case, of the Code of Business Conduct on behalf of our Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, and persons performing similar functions on the corporate governance section of our Internet website at www.williams.com, promptly following the date of any such amendment or waiver.

Item 11. Executive Compensation

The information required by Item 402 and paragraphs (e)(4) and (e)(5) of Item 407 of Regulation S-K regarding executive compensation will be presented under the headings “Compensation Discussion and Analysis,” “Executive Compensation Tables and Other Information,” “Director Compensation,” “Compensation and Management Development Committee Report on Executive Compensation,” and “Compensation and Management Development Committee Interlocks and Insider Participation” in our Proxy Statement, which information is incorporated by reference herein. Notwithstanding the foregoing, the information provided under the heading “Compensation and Management Development Committee Report on Executive Compensation” in our Proxy Statement is furnished and shall not be deemed to be filed for purposes of Section 18 of the Exchange Act, is not subject to the liabilities of that section and is not deemed incorporated by reference in any filing under the Securities Act.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information regarding securities authorized for issuance under equity compensation plans required by Item 201(d) of Regulation S-K and the security ownership of certain beneficial owners and management required by Item 403 of Regulation S-K will be presented under the headings “Equity Compensation Stock Plans” and “Security

140

Ownership of Certain Beneficial Owners and Management” in our Proxy Statement, which information is incorporated by reference herein.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information regarding certain relationships and related transactions required by Item 404 and Item 407(a) of Regulation S-K will be presented under the heading “Corporate Governance and Board Matters” in our Proxy Statement, which information is incorporated by reference herein.

Item 14. Principal Accountant Fees and Services

The information regarding our principal accounting fees and services required by Item 9(e) of Schedule 14A will be presented under the heading “Principal Accountant Fees and Services” in our Proxy Statement, which information is incorporated by reference herein.

141

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) 1 and 2.

	Page
Covered by report of independent auditors (PCAOB ID: 42):
Consolidated statement of income for each year in the three-year period ended December 31, 2022	75
Consolidated statement of comprehensive income (loss) for each year in the three-year period ended December 31, 2022	76
Consolidated balance sheet at December 31, 2022 and 2021	77
Consolidated statement of changes in equity for each year in the three-year period ended December 31, 2022	78
Consolidated statement of cash flows for each year in the three-year period ended December 31, 2022	79
Notes to consolidated financial statements	80
Schedule for each year in the three-year period ended December 31, 2022:
II — Valuation and qualifying accounts	136

All other schedules have been omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the financial statements and notes thereto.

(a) 3 and (b). The exhibits listed below are filed as part of this annual report.

INDEX TO EXHIBITS

Exhibit No.		Description
2.1	—	Agreement and Plan of Merger dated as of May 16, 2018, by and among The Williams Companies, Inc., SCMS LLC, Williams Partners L.P., and WPZ GP LLC (filed on May 17, 2018 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
2.2	—	Amendment No 1. to Agreement and Plan of Merger dated as of May 1, 2016, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (filed on May 3, 2016, as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
2.3	—	Agreement and Plan of Merger dated as of September 28, 2015, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC and Energy Transfer Equity GP, LLC (filed on October 1, 2015, as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.1	—	Amended and Restated Certificate of Incorporation, (filed on May 26, 2010, as Exhibit 3.(i)1 to The Williams Companies Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.2	—	Certificate of Designations of Series B Preferred Stock of the Williams Companies, Inc. (filed on July17, 2018, as Exhibit 3.1 to The Williams Companies, Inc. current report on Form 8-K (File No. 001-04174) and Incorporated herein by reference).

142

Exhibit No.		Description
3.3	—	Certificate of Amendment dated August 10, 2018 (filed on August 10, 2018, as Exhibit 3.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
3.4	—	By-laws of The Williams Companies, Inc., as last amended effective October 25, 2022 (filed on October 31, 2022, as Exhibit 3.4 to The Williams Companies Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
4.1	—	Senior Indenture, dated February 25, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed on February 25, 1997, as Exhibit 4.5.1 to MAPCO Inc.’s Amendment No. l to registration statement on Form S-3 (File No. 333-20837) and incorporated herein by reference).
4.2	—	Supplemental Indenture No. 2, dated March 5, 1997, between MAPCO Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed on March 4, 1998, as Exhibit 4(p) to MAPCO Inc.’s annual report on Form 10-K for the fiscal year ended December 31, 1997 (File No. 001-05254) and incorporated herein by reference).
4.3	—	Supplemental Indenture No. 3, dated March 31, 1998, among MAPCO Inc., Williams Holdings of Delaware, Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed on March 30, 1999, as Exhibit 4(J) to Williams Holdings of Delaware, Inc.’s annual report on Form 10-K for the fiscal year ended December 31, 1998 (File No. 000-20555) and incorporated herein by reference).
4.4	—	Fourth Supplemental Indenture, dated as of July 31, 1999, among Williams Holdings of Delaware, Inc., The Williams Companies, Inc. and Bank One Trust Company, N.A. (formerly The First National Bank of Chicago), as Trustee (filed on March 28, 2000, as Exhibit 4(q) to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
4.5	—	Fifth Supplemental Indenture, dated as of February 1, 2010, between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010, as Exhibit 4.3 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.6	—	Fifth Supplemental Indenture between The Williams Companies, Inc. and Bank One Trust Company, N.A., as Trustee, dated as of January 17, 2001 (filed on March 12, 2001, as Exhibit 4(k) to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
4.7	—	Seventh Supplemental Indenture, dated March 19, 2002, between The Williams Companies, Inc. as Issuer and Bank One Trust Company, National Association, as Trustee (filed on May 9, 2002, as Exhibit 4.1 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
4.8	—	Eleventh Supplemental Indenture, dated as of February 1, 2010, between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on February 2, 2010, as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.9	—	Indenture, dated December 18, 2012, between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. as trustee (filed on December 20, 2012, as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).

143

Exhibit No.		Description
4.10	—	Second Supplemental Indenture, dated as of June 24, 2014, between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on June 24, 2014, as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.11	—	Third Supplemental Indenture, dated as of May 14, 2020, between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on May 14, 2020, as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.12	—	Fourth Supplemental Indenture, dated as of March 2, 2021, between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 2, 2021, as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.13	—	Fifth Supplemental Indenture, dated as of October 8, 2021, between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on October 8, 2021, as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.14	—	Sixth Supplemental Indenture, dated as of August 8, 2022, between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 8, 2022, as Exhibit 4.1) to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.15	—	Indenture, dated as of February 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 10, 2010, as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.16	—	First Supplemental Indenture, dated as of February 2, 2015, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015, as Exhibit 4.5 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
4.17	—	Second Supplemental Indenture, dated as of August 10, 2018, between The Williams Companies, Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on August 10, 2018, as Exhibit 4.2 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.18	—	Indenture, dated as of November 9, 2010, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 12, 2010, as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
4.19	—	Fourth Supplemental Indenture, dated as of November 15, 2013, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on November 18, 2013, as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
4.20	—	Fifth Supplemental Indenture, dated as of March 4, 2014, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 4, 2014, as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).

144

Exhibit No.		Description
4.21	—	Sixth Supplemental Indenture, dated as of June 27, 2014, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on June 27, 2014, as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-32599) and incorporated herein by reference).
4.22	—	Seventh Supplemental Indenture, dated as of February 2, 2015, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A. (filed on February 3, 2015, as Exhibit 4.4 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
4.23	—	Eighth Supplemental Indenture, dated as of March 3, 2015, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 3, 2015, as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
4.24	—	Ninth Supplemental Indenture, dated as of June 5, 2017, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on June 5, 2017, as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
4.25	—	Tenth Supplemental Indenture, dated as of March 5, 2018, between Williams Partners L.P. and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 5, 2018, as Exhibit 4.1 to Williams Partners L.P.’s current report on Form 8-K (File No. 001-34831) and incorporated herein by reference).
4.26	—	Eleventh Supplemental Indenture, dated as of August 10, 2018, between The Williams Companies Inc. and The Bank of New York Mellon Trust Company, N.A. (filed on August 10, 2018, as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.27	—	Senior Indenture, dated as of November 30, 1995, between Northwest Pipeline Corporation and Chemical Bank, Trustee (filed September 14, 1995, as Exhibit 4.1 to Northwest Pipeline’s registration statement on Form S-3 (File No. 033-62639) and incorporated herein by reference).
4.28	—	Indenture, dated as of April 3, 2017, between Northwest Pipeline LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on April 3, 2017, as Exhibit 4.1 to Northwest Pipeline’s current report on Form 8-K (File No. 001-07414) and incorporated herein by reference).
4.29	—	Senior Indenture, dated as of July 15, 1996, between Transcontinental Gas Pipe Line Corporation and Citibank, N.A., as Trustee (filed on April 2, 1996, as Exhibit 4.1 to Transcontinental Gas Pipe Line Corporation’s registration statement on Form S-3 (File No. 333-02155) and incorporated herein by reference).
4.30	—	Indenture, dated as of August 12, 2011, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on August 12, 2011, as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.31	—	Indenture, dated as of July 13, 2012, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on July 16, 2012 as Exhibit 4.1 to Transcontinental Gas Pipe Line Company, LLC’s current report on Form 8-K (File No. 001-07584) and incorporated herein by reference).
4.32	—	Indenture, dated as of January 22, 2016, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on January 22, 2016, as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).

145

Exhibit No.		Description
4.33	—	Indenture, dated as of March 15, 2018, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on March 15, 2018, as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.34	—	Indenture, dated as of May 8, 2020, between Transcontinental Gas Pipe Line Company, LLC and The Bank of New York Mellon Trust Company, N.A., as trustee (filed on May 8, 2020, as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
4.35*	—	Description of Securities.
10.1§	—	Form of Director and Officer Indemnification Agreement (filed on September 24, 2008, as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.2§	—	Form of 2013 Nonqualified Stock Option Agreement among Williams and certain employees and officers (filed on February 27, 2013, as Exhibit 10.6 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.3§	—	Form of 2013 Restricted Stock Unit Agreement among Williams and certain nonmanagement directors (filed on February 26, 2014, as Exhibit 10.11 to The Williams Companies, Inc. annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.4§	—	Form of 2014 Nonqualified Stock Option Agreement among Williams and certain employees and officers (filed on February 26, 2014, as Exhibit 10.8 to The Williams Companies, Inc. annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.5§	—	Form of 2014 Restricted Stock Unit Agreement among Williams and certain nonmanagement directors (filed on February 25, 2015, as Exhibit 10.12 to The Williams Companies, Inc. annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.6§	—	Form of 2015 Time-Based Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on February 25, 2015, as Exhibit 10.16 to The Williams Companies, Inc. annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.7§	—	Form of 2015 Nonqualified Stock Option Agreement among Williams and certain employees and officers (filed on February 25, 2015, as Exhibit 10.17 to The Williams Companies, Inc. annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.8§	—	Form of 2016 Time-Based Restricted Stock Unit Agreement among Williams and certain non-management directors (filed on February 22, 2017, as Exhibit 10.21 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.9§	—	Form of 2016 Nonqualified Stock Option Agreement among Williams and certain employees and officers (filed on February 22, 2017, as Exhibit 10.22 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.10§	—	Form of 2017 Time-Based Restricted Stock Unit Agreement among Williams and certain non-management directors (filed on February 22, 2017, as Exhibit 10.24 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.11§	—	Form of 2017 Nonqualified Stock Option Agreement among Williams and certain employees and officers (filed on February 22, 2017, as Exhibit 10.25 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).

146

Exhibit No.		Description
10.12§	—	Form of 2018 Nonqualified Stock Option Agreement among Williams and certain employees and officers (filed on May 3, 2018, as Exhibit 10.5 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.13	—	Form of 2018 Time-Based Restricted Stock Unit Agreement among Williams and certain non-management directors (filed on August 2, 2018, as Exhibit 10.2 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.14§	—	Form of Amended 2019 Executive Performance-Based Restricted Stock Unit Agreement between The Williams Companies, Inc. and certain employees and officers (filed on November 1, 2021, as Exhibit 10.4 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.15§	—	Amended Form of 2019 Performance-Based Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on May 4, 2020, as Exhibit 10.1 to The Williams Companies Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.16§	—	Form of Amended 2019 Performance-Based Restricted Stock Unit Agreement between The Williams Companies, Inc. and certain employees and officers (filed on November 1, 2021, as Exhibit 10.3 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.17§	—	Form of 2019 Time-Based Restricted Stock Unit Agreement among Williams and certain employees and officers (filed on May 2, 2019, as Exhibit 10.3 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.18§	—	Form of Amended 2019 Time-Based Restricted Stock Unit Agreement between The Williams Companies, Inc. and certain employees and officers (filed on November 1, 2021, as Exhibit 10.2 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.19§	—	Form of 2019 Time-Based Restricted Stock Unit Agreement among Williams and certain non-management directors (filed on May 2, 2019, as Exhibit 10.4 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.20§	—	Form of 2020 Performance-Based Restricted Stock Unit Agreement among The Williams Companies, Inc. and certain employees and officers (filed on May 4, 2020, as Exhibit 10.2 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.21§	—	Form of Amended 2020 Performance-Based Restricted Stock Unit Agreement between The Williams Companies, Inc. and certain employees and officers (filed on November 1, 2021, as Exhibit 10.6 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.22§	—	Form of 2020 Time-Based Restricted Stock Unit Agreement among The Williams Companies, Inc. and certain employees and officers (filed on May 4, 2020, as Exhibit 10.3 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.23§	—	Form of Amended 2020 Time-Based Restricted Stock Unit Agreement between The Williams Companies, Inc. and certain employees and officers (filed on November 1, 2021, as Exhibit 10.5 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).

147

Exhibit No.		Description
10.24§	—	Form of 2020 Time-Based Restricted Stock Unit Agreement among The Williams Companies, Inc. and certain non-management directors (filed on May 4, 2020, as Exhibit 10.4 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.25§	—	Form of Amended 2021 Time-Based Restricted Stock Unit Agreement between The Williams Companies, Inc. and certain employees and officers (filed on November 1, 2021, as Exhibit 10.7 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.26§	—	Form of 2021 Performance-Based Restricted Stock Unit Agreement between The Williams Companies, Inc. and certain employees and officers (filed on May 3, 2021, as Exhibit 10.1 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.27§	—	Form of Amended 2021 Performance-Based Restricted Stock Unit Agreement between The Williams Companies, Inc. and certain employees and officers (filed on November 1, 2021, as Exhibit 10.8 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.28§	—	Form of 2021 Time-Based Restricted Stock Unit Agreement among The Williams Companies, Inc. and certain employees and officers (filed on February 24, 2021, as Exhibit 10.28 to The Williams Companies, Inc.’s Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.29§	—	Form of Time-Based Restricted Stock Unit Agreement among The Williams Companies, Inc. and certain employees and officers (filed on February 28, 2022, as Exhibit 10.31 to The Williams Companies, Inc.’s Form 10-K (File No.001-04174) and incorporated herein by reference).
10.30§	—	Form of Time-Based Restricted Stock Unit Agreement among The Williams Companies, Inc. and certain non-management directors (filed on February 24, 2021, as Exhibit 10.29 to The Williams Companies, Inc.’s Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.31§	—	Form of Performance-Based Restricted Stock Unit Agreement among The Williams Companies, Inc. and certain employees and officers (filed on February 28, 2022, as Exhibit 10.33 to The Williams Companies, Inc.’s Form 10-K (File No.001-04174) and incorporated herein by reference.
10.32§	—	Change in Control and Restrictive Covenant Agreement between certain executive officers (Tier One Executives) and The Williams Companies, Inc. (filed on February 24, 2020, as Exhibit 10.29 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.33§	—	Change in Control and Restrictive Covenant Agreement between certain executive officers (Tier Two Executives) and The Williams Companies, Inc. (filed on February 24, 2020, as Exhibit 10.30 to The Williams Companies, Inc.’s annual report on Form 10-K (File No. 001-04174) and incorporated herein by reference).
10.34§	—	The Williams Companies, Inc. Executive Severance Pay Plan, as amended and restated, effective August 1, 2022 (filed October 31, 2022, as Exhibit 10.1 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).
10.35§	—	The Williams Companies, Inc. 2007 Incentive Plan as amended and restated effective October 26, 2021 (filed on November 1, 2021, as Exhibit 10.9 to The Williams Companies, Inc.’s quarterly report on Form 10-Q (File No. 001-04174) and incorporated herein by reference).

148

Exhibit No.		Description
10.36	—	Amended and Restated Credit Agreement dated as of October 8, 2021, between The Williams Companies, Inc., Northwest Pipeline LLC, and Transcontinental Gas Pipe Line Company, LLC, as borrowers, the lenders named therein, and Wells Fargo Bank, National Association, as Administrative Agent (filed on October 8, 2021, as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
10.37	—	Form of Commercial Paper Dealer Agreement, dated as of August 10, 2018, between The Williams Companies, Inc., as Issuer, and the Dealer party thereto (filed on August 10, 2018, as Exhibit 10.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference).
21*	—	Subsidiaries of the registrant.
23.1*	—	Consent of Independent Registered Public Accounting Firm, Ernst & Young LLP.
23.2*	—	Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers LLP.
31.1*	—	Certification of the Chief Executive Officer pursuant to Rules 13a-l4(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(3l) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	—	Certification of the Chief Financial Officer pursuant to Rules 13a-14(a) and l5d-l4(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32**	—	Certification of the Chief Executive Officer and the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	—	XBRL Instance Document. The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the inline XBRL document.
101.SCH*	—	XBRL Taxonomy Extension Schema.
101.CAL*	—	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*	—	XBRL Taxonomy Extension Definition Linkbase.
101.LAB*	—	XBRL Taxonomy Extension Label Linkbase.
101.PRE*	—	XBRL Taxonomy Extension Presentation Linkbase.
104*	—	Cover Page Interactive Data File. The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document (contained in Exhibit 101).

______________
*	Filed herewith
**	Furnished herewith
§	Management contract or compensatory plan or arrangement

149

Item 16. Form 10-K Summary

Not applicable.

150

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

THE WILLIAMS COMPANIES, INC. (Registrant)
By:	/s/ MARY A. HAUSMAN
	Mary A. Hausman Vice President, Chief Accounting Officer and Controller

Date: February 27, 2023

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/    ALAN S. ARMSTRONG	President, Chief Executive Officer and Director	February 27, 2023
Alan S. Armstrong	(Principal Executive Officer)
/s/    JOHN D. PORTER	Senior Vice President and Chief Financial Officer	February 27, 2023
John D. Porter	(Principal Financial Officer)
/s/    MARY A. HAUSMAN	Vice President, Chief Accounting Officer and Controller	February 27, 2023
Mary A. Hausman	(Principal Accounting Officer)
/s/    STEPHEN W. BERGSTROM	Chairman of the Board	February 27, 2023
Stephen W. Bergstrom
/s/    MICHAEL A. CREEL	Director	February 27, 2023
Michael A. Creel
/s/ STACEY H. DORÉ	Director	February 27, 2023
Stacey H. Doré
/s/ CARRI LOCKHART	Director	February 27, 2023
Carri Lockhart
/s/ RICHARD E. MUNCRIEF	Director	February 27, 2023
Richard E. Muncrief
/s/    PETER A. RAGAUSS	Director	February 27, 2023
Peter A. Ragauss
/s/ ROSE M. ROBESON	Director	February 27, 2023
Rose M. Robeson
/s/   SCOTT D. SHEFFIELD	Director	February 27, 2023
Scott D. Sheffield

151

Signature	Title	Date
/s/    MURRAY D. SMITH	Director	February 27, 2023
Murray D. Smith
/s/    WILLIAM H. SPENCE	Director	February 27, 2023
William H. Spence
/s/    JESSE J. TYSON	Director	February 27, 2023
Jesse J. Tyson

152

EX-4.35

Exhibit 4.35

DESCRIPTION OF THE REGISTRANT’S SECURITIES

REGISTERED PURSUANT TO SECTION 12 OF THE

SECURITIES EXCHANGE ACT OF 1934

As of the date of the Annual Report on Form 10-K of which this exhibit is a part, The Williams Companies, Inc. (“Williams”) has one class of security registered under Section 12 of the Securities Exchange Act of 1934, as amended: our common stock, $1.00 par value per share.

Description of Common Stock

The following description of our common stock is a summary and does not purport to be complete. It is subject to and qualified in its entirety by reference to our Amended and Restated Certificate of Incorporation, as supplemented and as amended (our “charter”), and our By-Laws (our “bylaws”), each of which are incorporated by reference as an exhibit to the Annual Report on Form 10-K of which this exhibit is a part. We encourage you to read our charter, our bylaws and the applicable provisions of Delaware General Corporation Law (the “DGCL”) for additional information.

General

Our charter authorizes the issuance of up to 1,470,000,000 shares of our common stock. The outstanding shares of common stock are fully paid and nonassessable. The holders of common stock are not entitled to preemptive or redemption rights. Shares of common stock are not convertible into shares of any other class of capital stock. Computershare Trust Company, N.A. is the transfer agent and registrar for our common stock. Our common stock is listed on the New York Stock Exchange under the ticker symbol “WMB.”

Dividends

The holders of our common stock are entitled to receive dividends when, as, and if declared by our board of directors, out of funds legally available for their payment subject to the rights of holders of any outstanding preferred stock.

Voting Rights

The holders of our common stock are entitled to one vote per share on all matters submitted to a vote of stockholders. Except as otherwise provided by law, our charter or our bylaws, at each meeting of the stockholders, all corporate actions to be taken by vote of the stockholders shall be authorized by a majority of the votes cast by the stockholders entitled to vote thereon, present in person or represented by proxy. Director nominees in uncontested elections must receive a majority of the votes cast to be elected, and director nominees in contested elections must receive a plurality of the votes cast to be elected. A vote of 75% of the outstanding shares of our common stock is required to amend certain provisions of our charter and for stockholders to amend our bylaws.

Rights Upon Liquidation

In the event of our voluntary or involuntary liquidation, dissolution, or winding up of the affairs of Williams, the holders of our common stock will be entitled to share equally in any assets available for distribution after the payment in full of all debts and distributions and after the holders of all series of outstanding preferred stock have received their liquidation preferences in full.

1

Exhibit 4.35

Anti-Takeover Provisions

We currently have the following provisions in our charter or bylaws that could be considered to be “anti-takeover” provisions:

•an article in our charter requiring the affirmative vote of three-fourths of the outstanding shares of common stock for certain merger and asset sale transactions with holders of more than five percent of the voting power of Williams;

•a bylaw that only permits our chairman of the board, chief executive officer or a majority of the board to call a special meeting of the stockholders; and

•a bylaw requiring stockholders to provide prior notice for nominations for election to the board of directors or for proposing matters which can be acted upon at stockholders meetings.

We are a Delaware corporation and are subject to Section 203 of the DGCL. In general, Section 203 prevents an interested stockholder, which is defined generally as a person owning 15% or more of our outstanding voting stock, from engaging in a business combination with us for three years following the date that person became an interested stockholder unless:

•before that person became an interested stockholder, our board of directors approved the transaction in which the interested stockholder became an interested stockholder or approved the business combination;

•upon completion of the transaction that resulted in the interested stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of our voting stock outstanding at the time the transaction commenced (excluding stock held by persons who are both directors and officers of Williams or by certain employee stock plans); or

•on or following the date on which that person became an interested stockholder, the business combination is approved by our board of directors and authorized at a meeting of stockholders by the affirmative vote of the holders of at least 66 2⁄3% of our outstanding voting stock (excluding shares held by the interested stockholder).

A business combination includes mergers, asset sales and other transactions resulting in a financial benefit to the interested stockholder.

2

EX-21

	Exhibit 21
ENTITY	JURISDICTION
Alliance Canada Marketing L.P.	Alberta
Alliance Canada Marketing LTD	Alberta
Appalachia Midstream Services, L.L.C.	Oklahoma
Aurora Hydrogen Inc.	Alberta
Aux Sable Liquid Products Inc.	Delaware
Aux Sable Liquid Products LP	Delaware
Aux Sable Midstream LLC	Delaware
BPEH-CXL Holdings LLC	Delaware
Bargath LLC	Delaware
Baton Rouge Fractionators LLC	Delaware
Baton Rouge Pipeline LLC	Delaware
Black Marlin Pipeline LLC	Texas
Blue Racer Midstream, LLC	Delaware
Blue Racer Midstream Holdings, LLC	Delaware
Blue Racer Midstream Intermediate Holdings, LLC	Delaware
Bluebonnet Market Express LLC	Delaware
Bluestem Gas Services, L.L.C.	Oklahoma
Bluestem Pipeline LLC	Delaware
Branch Midstream Company, LLC	Texas
Brazos Permian II, LLC	Delaware
Carbon County UCG, Inc.	Delaware
Carbonate Trend Pipeline LLC	Delaware
Cardinal Gas Services, L.L.C.	Delaware
Cardinal Operating Company, LLC	Delaware
Cardinal Pipeline Company, LLC	North Carolina
DMP NEW YORK, INC.	New York
Discovery Gas Transmission LLC	Delaware
Discovery Producer Services LLC	Delaware
Emerging Energy Ventures, LLC	Delaware
Encino Environmental Holdings LLC	Delaware
Endeavor Gathering LLC	Delaware
Gemini Arklatex, LLC	Delaware
Gemini Arklatex Services, LLC	Delaware
Gemini Carthage Pipeline, LLC	Delaware
Gulfstar One LLC	Delaware
Gulfstream Management & Operating Services, L.L.C.	Delaware
Gulfstream Natural Gas System, L.L.C.	Delaware
HB Construction Company Ltd.	Alberta
Hill-Lake Gas Storage, LLC	Texas

	Exhibit 21
ENTITY	JURISDICTION
Inland Ports, Inc.	Tennessee
Kiowa Lateral LLC	Delaware
Laurel Mountain Midstream Operating LLC	Delaware
Laurel Mountain Midstream, LLC	Delaware
Louisiana Energy Gateway LLC	Delaware
Louisiana Midstream Gas Services, L.L.C.	Oklahoma
Magnolia Midstream Gas Services, L.L.C.	Oklahoma
Marsh Resources, LLC	Delaware
Mid-Continent Fractionation and Storage, LLC	Delaware
Mockingbird Midstream Gas Services, L.L.C.	Oklahoma
Monarch Pipeline LLC	Delaware
NT Minerals, LLC	Texas
New Energy Ventures Holdco, LLC	Delaware
NorTex Development Company, LLC	Delaware
NorTex Midstream Holdings, LLC	Delaware
NorTex Midstream Partners, LLC	Delaware
NorTex Trading and Marketing, LLC	Texas
Northwest Pipeline LLC	Delaware
Ohio Valley Midstream LLC	Delaware
Oklahoma Midstream Gas Services, L.L.C.	Oklahoma
Orbital Sidekick, Inc.	Delaware
Overland Pass Pipeline Company LLC	Delaware
Pacific Connector Gas Pipeline, LP	Delaware
Parachute Pipeline LLC	Delaware
Permian Connector, LLC	Delaware
Pine Needle LNG Company, LLC	North Carolina
Pine Needle Operating Company, LLC	Delaware
Ponder Midstream Gas Services, L.L.C.	Delaware
Reserveco Inc.	Delaware
Rocky Mountain Midstream Holdings LLC	Delaware
Rocky Mountain Midstream JV Holdings LLC	Delaware
Rocky Mountain Midstream LLC	Texas
Rocky Mountain Midstream Marketing LLC	Texas
Rocky Mountain Midstream Pipeline LLC	Texas
Rocky Mountain Midstream Water LLC	Texas
Sequent Energy Canada LLC	Delaware
Sequent Energy Management LLC	Delaware
Socagee Midstream Gas Services LLC	Delaware
South Mansfield E&P, LLC	Delaware
Star Gathering, LLC	Delaware

	Exhibit 21
ENTITY	JURISDICTION
TWC Holdings C.V.	Netherlands
Targa Train 7 LLC	Delaware
Texas Midstream Gas Services, L.L.C.	Oklahoma
The Williams Companies Foundation, Inc.	Oklahoma
The Williams Companies International Holdings B.V.	Dutch BV
Three Rivers Midstream LLC	Delaware
TransCardinal Company, LLC	Delaware
TransCarolina LNG Company, LLC	Delaware
Transco Exploration Company	Delaware
Transcontinental Gas Pipe Line Company, LLC	Delaware
UEOM NGL Pipelines LLC	Delaware
Utica East Ohio Midstream LLC	Delaware
Utica Gas Services, L.L.C.	Oklahoma
WFS - Liquids LLC	Delaware
WFS Gathering Company, L.L.C.	Delaware
Wamsutter LLC	Delaware
Wamsutter E&P, LLC	Delaware
WilPro Energy Services (El Furrial) Limited	Cayman Islands
WilPro Energy Services (Pigap II) Limited	Cayman Islands
Williams ACM Holdings ULC	British Columbia
Williams Acquisition Holding Company LLC	New Jersey
Williams Alaska Petroleum, Inc.	Alaska
Williams Bayou Ethane Pipeline, LLC	Delaware
Williams Blu Operating LLC	Delaware
Williams CRE LLC	Delaware
Williams CV Holdings LLC	Delaware
Williams Compression LLC	Oklahoma
Williams Energy Solutions LLC	Delaware
Williams Express LLC	Delaware
Williams Express, Inc.	Alaska
Williams Field Services - Gulf Coast Company LLC	Delaware
Williams Field Services Company, LLC	Delaware
Williams Field Services Group, LLC	Delaware
Williams Flexible Generation, LLC	Delaware
Williams Gas Processing - Gulf Coast Company LLC	Delaware
Williams Global Energy (Cayman) Limited	Cayman Islands
Williams Global Holdings LLC	Delaware
Williams Gulf Coast Transportation Company LLC	Delaware
Williams Headquarters Building LLC	Delaware
Williams Holdings and Manufacturing LLC	Delaware

	Exhibit 21
ENTITY	JURISDICTION
Williams Hutch Rail Company, LLC	Delaware
Williams Information Technology LLC	Delaware
Williams International Company LLC	Delaware
Williams International El Furrial Limited	Cayman Islands
Williams International Pigap Limited	Cayman Islands
Williams International Venezuela Limited	Cayman Islands
Williams Laurel Mountain, LLC	Delaware
Williams MLP Operating, LLC	Delaware
Williams Midstream Gas Services LLC	Oklahoma
Williams Mobile Bay Producer Services, L.L.C.	Delaware
Williams Ohio River Valley Corporation	Delaware
Williams Ohio River Valley LLC	Delaware
Williams Ohio Valley Midstream LLC	Texas
Williams Ohio Valley Pipeline LLC	Delaware
Williams Oil Gathering, L.L.C.	Delaware
Williams Olefins Feedstock Pipelines, L.L.C.	Delaware
Williams Olefins Pipeline Holdco LLC	Delaware
Williams PERK, LLC	Delaware
Williams Pacific Connector Gas Operator, LLC	Delaware
Williams Partners Operating LLC	Delaware
Williams Petroleum Services, LLC	Delaware
Williams Pipeline Services LLC	Delaware
Williams Propylene Company LLC	Delaware
Williams Resource Center, L.L.C.	Delaware
Williams Rocky Mountain Midstream Holdings LLC	Delaware
Williams Rocky Mountain Midstream Operating LLC	Delaware
Williams Solar Holdco LLC	Delaware
Williams Strategic Sourcing Company LLC	Delaware
Williams Upstream Holdings, LLC	Delaware
Williams WPC - I, LLC	Delaware
Worsham-Steed Gas Storage, LLC	Texas

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

(1)Registration Statement (Form S-3 Nos. 333-29185 and 333-253451) of The Williams Companies, Inc.,

(2)    Registration Statement (Form S-8 No. 333-03957) pertaining to The Williams Companies, Inc. 1996 Stock Plan for Non-Employee Directors,

(3)    Registration Statement (Form S-8 No. 333-85542) pertaining to The Williams Investment Plus Plan,

(4)    Registration Statement (Form S-8 No. 333-85546) pertaining to The Williams Companies, Inc. 2002 Incentive Plan,

(5)    Registration Statement (Form S-8 No. 333-142985) pertaining to The Williams Companies, Inc. 2007 Employee Stock Purchase Plan and The Williams Companies, Inc. 2007 Incentive Plan,

(6)    Registration Statement (Form S-8 No. 333-167123) pertaining to The Williams Companies, Inc. 2007 Incentive Plan, and

(7)    Registration Statement (Form S-8 No. 333-198050) pertaining to The Williams Companies, Inc. 2007 Incentive Plan and The Williams Companies, Inc. 2007 Employee Stock Purchase Plan;

of our reports dated February 27, 2023, with respect to the consolidated financial statements and schedule of The Williams Companies, Inc. and the effectiveness of internal control over financial reporting of The Williams Companies, Inc. included in this Annual Report (Form 10-K) of The Williams Companies, Inc. for the year ended December 31, 2022.

/s/ Ernst & Young LLP

Tulsa, Oklahoma
February 27, 2023

EX-23.2

Exhibit 23.2

Consent of Independent Registered Public Accounting Firm

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-29185 and 333-253451) and Form S-8 (Nos. 333-03957, 333-85542, 333-85546, 333-142985, 333-167123 and 333-198050) of The Williams Companies, Inc. of our report dated February 27, 2023 relating to the financial statements of Gulfstream Natural Gas System, L.L.C., which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 27, 2023

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Alan S. Armstrong, certify that:

1.    I have reviewed this annual report on Form 10-K of The Williams Companies, Inc.;

2.    Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.    Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.    The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.    The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 27, 2023

/s/ Alan S. Armstrong

Alan S. Armstrong

President and Chief Executive Officer

(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, John D. Porter, certify that:

1.    I have reviewed this annual report on Form 10-K of The Williams Companies, Inc.;

2.    Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.    Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.    The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.    The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 27, 2023

/s/ John D. Porter

John D. Porter

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of The Williams Companies, Inc. (the “Company”) on Form 10-K for the period ending December 31, 2022, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned hereby certifies, in his capacity as an officer of the Company, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Alan S. Armstrong

Alan S. Armstrong

President and Chief Executive Officer

February 27, 2023

/s/ John D. Porter

John D. Porter

Senior Vice President and Chief Financial Officer

February 27, 2023

A signed original of this written statement required by Section 906 has been provided to, and will be retained by, the Company and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished to the Securities and Exchange Commission as an exhibit to the Report and shall not be considered filed as part of the Report.

XML

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2022	Feb. 17, 2023	Jun. 30, 2022
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	1-4174
Entity Registrant Name	Williams Companies, Inc.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	73-0569878
Entity Address, Address Line One	One Williams Center
Entity Address, City or Town	Tulsa
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	74172
City Area Code	800
Local Phone Number	945-5426
Title of 12(b) Security	Common Stock, $1.00 par value
Trading Symbol	WMB
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
DocumentFinStmtErrorCorrectionFlag	false
Entity Shell Company	false
Entity Public Float			$ 36,889,420,649
Entity Common Stock, Shares Outstanding		1,218,562,959
Documents Incorporated by Reference [Text Block]	Portions of the Registrant’s Definitive Proxy Statement for the Registrant’s Annual Meeting of Stockholders to be held on April 25, 2023, are incorporated into Part III, as specifically set forth in Part III.
Entity Central Index Key	0000107263
Amendment Flag	false
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY

XML

Audit Information	12 Months Ended
	Dec. 31, 2022
Audit Information [Abstract]
Auditor Name	Ernst & Young LLP
Auditor Location	Tulsa, Oklahoma
Auditor Firm ID	42

XML

Consolidated Statement of Income - USD ($) shares in Thousands, $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenues:
Revenues		$ 10,965	$ 10,627	$ 7,719
Costs and expenses:
Operating and maintenance expenses		1,817	1,548	1,326
Depreciation and amortization expenses		2,009	1,842	1,721
Selling, general, and administrative expenses		636	558	466
Impairment of certain assets (Note 15)		0	2	182
Impairment of goodwill (Note 15)		0	0	187
Other (income) expense – net		28	14	22
Total costs and expenses		7,947	7,996	5,517
Operating income (loss)		3,018	2,631	2,202
Equity earnings (losses) (Note 8)		637	608	328
Impairment of equity-method investments (Note 15)		0	0	(1,046)
Other investing income (loss) – net		16	7	8
Interest incurred		(1,167)	(1,190)	(1,192)
Interest capitalized		20	11	20
Other income (expense) – net		18	6	(43)
Income (loss) before income taxes		2,542	2,073	277
Less: Provision (benefit) for income taxes		425	511	79
Net income (loss)		2,117	1,562	198
Less: Net income (loss) attributable to noncontrolling interests		68	45	(13)
Amounts attributable to The Williams Companies, Inc. available to common stockholders:
Net income (loss) attributable to The Williams Companies, Inc.		2,049	1,517	211
Less: Preferred stock dividends		3	3	3
Net income (loss) available to common stockholders		$ 2,046	$ 1,514	$ 208
Basic earnings (loss) per common share:
Net income (loss)		$ 1.68	$ 1.25	$ 0.17
Weighted-average shares (thousands)		1,218,362	1,215,221	1,213,631
Diluted earnings (loss) per common share:
Net income (loss)		$ 1.67	$ 1.24	$ 0.17
Weighted-average shares (thousands)		1,222,672	1,218,215	1,215,165
Service [Member]
Revenues:
Revenues		$ 6,536	$ 6,001	$ 5,924
NonRegulated Service Commodity Consideration [Member]
Revenues:
Revenues		260	238	129
Product [Member]
Revenues:
Revenues		4,556	4,536	1,671
Energy Commodities and Service
Revenues:
Revenues	[1]	(387)	(148)	(5)
Oil and Gas, Purchased [Member]
Costs and expenses:
Cost of Goods and Service, Excluding Depreciation, Depletion, and Amortization		3,369	3,931	1,545
Natural Gas Purchased For Shrink [Member]
Costs and expenses:
Cost of Goods and Service, Excluding Depreciation, Depletion, and Amortization		$ 88	$ 101	$ 68

[1] We record transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue.

XML

Consolidated Statement of Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Comprehensive income (loss):
Net income (loss)	$ 2,117	$ 1,562	$ 198
Designated cash flow hedging activities:
Net unrealized gain (loss) from derivative instruments, net of taxes of $1, $14, and $— in 2022, 2021, and 2020, respectively	(3)	(40)	(2)
Reclassifications into earnings of net derivative instruments (gain) loss, net of taxes of $—, ($14), and $— in 2022, 2021, and 2020, respectively	0	41	1
Pension and other postretirement benefits:
Net actuarial gain (loss) arising during the year, net of taxes of $1, ($18), and ($27) in 2022, 2021, and 2020, respectively	1	51	81
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($4), ($4), and ($7) in 2022, 2021, and 2020, respectively	11	11	23
Other comprehensive income (loss)	9	63	103
Comprehensive income (loss)	2,126	1,625	301
Less: Comprehensive income (loss) attributable to noncontrolling interests	68	45	(13)
Comprehensive income (loss) attributable to The Williams Companies, Inc.	$ 2,058	$ 1,580	$ 314

XML

Consolidated Statement of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash flow hedging activities:
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), before Reclassification, Tax	$ 1	$ 14	$ 0
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, Tax	0	(14)	0
Pension and other postretirement benefits:
Other Comprehensive Income (Loss), Defined Benefit Plan, Net Actuarial Gain (Loss) Arising During Period, Tax	1	(18)	(27)
Other Comprehensive Income Loss, Reclassification Pension And Other Postretirement Benefit Plans Net Gain Loss Included In Net Periodic Benefit Cost (Credit), Tax	$ (4)	$ (4)	$ (7)

XML

Consolidated Balance Sheet - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents	$ 152	$ 1,680
Trade accounts and other receivables	2,729	1,986
Allowance for doubtful accounts	(6)	(8)
Trade accounts and other receivables – net	2,723	1,978
Inventories	320	379
Derivative assets	323	301
Other current assets and deferred charges	279	211
Total current assets	3,797	4,549
Investments	5,065	5,127
Property, plant, and equipment – net	30,889	29,258
Intangible assets – net of accumulated amortization	7,363	7,402
Regulatory assets, deferred charges, and other	1,319	1,276
Total assets	48,433	47,612
Current liabilities:
Accounts payable	2,327	1,746
Derivative Liability, Current	316	166
Accrued and other current liabilities	1,270	1,035
Commercial Paper	350	0
Long-term debt due within one year	627	2,025
Total current liabilities	4,890	4,972
Long-term debt	21,927	21,650
Deferred income tax liabilities	2,887	2,453
Regulatory liabilities, deferred income, and other	4,684	4,436
Contingent liabilities and commitments (Note 17)
Stockholders’ equity:
Preferred stock ($1 par value; 30 million shares authorized at December 31, 2022 and December 31, 2021; 35,000 shares issued at December 31, 2022 and December 31, 2021)	35	35
Common stock ($1 par value; 1,470 million shares authorized at December 31, 2022 and December 31, 2021; 1,253 million shares issued at December 31, 2022 and 1,250 million shares issued at December 31, 2021)	1,253	1,250
Capital in excess of par value	24,542	24,449
Retained deficit	(13,271)	(13,237)
Accumulated other comprehensive income (loss)	(24)	(33)
Treasury stock, at cost (35 million shares of common stock)	(1,050)	(1,041)
Total stockholders’ equity	11,485	11,423
Noncontrolling interests in consolidated subsidiaries	2,560	2,678
Total equity	14,045	14,101
Total liabilities and equity	$ 48,433	$ 47,612

XML

Consolidated Balance Sheet (Parenthetical) - $ / shares	Dec. 31, 2022	Dec. 31, 2021
Common Stock, Par or Stated Value Per Share	$ 1	$ 1
Common Stock, Shares Authorized	1,470,000,000	1,470,000,000
Common Stock, Shares, Issued	1,253,000,000	1,250,000,000
Treasury Stock, Shares	35,000,000	35,000,000
Series B Preferred Stock [Member]
Preferred Stock, Par or Stated Value Per Share	$ 1	$ 1
Preferred Stock, Shares Authorized	30,000,000	30,000,000
Preferred Stock, Shares Issued	35,000	35,000

XML

Consolidated Statement of Changes in Equity - USD ($) $ in Millions	Total	Preferred Stock	Common Stock	Capital in Excess of Par Value	Retained Deficit	Accumulated Other Comprehensive Income (Loss)	Treasury Stock	Total Stockholders' Equity	Noncontrolling Interests
Beginning balance at Dec. 31, 2019	$ 16,364	$ 35	$ 1,247	$ 24,323	$ (11,002)	$ (199)	$ (1,041)	$ 13,363	$ 3,001
Net income (loss)	198	0	0	0	211	0	0	211	(13)
Other comprehensive income (loss)	103	0	0	0	0	103	0	103	0
Dividends, Common Stock, Cash	(1,941)	0	0	0	(1,941)	0	0	(1,941)	0
Dividends and distributions to noncontrolling interests	(185)	0	0	0	0	0	0	0	(185)
Stock-based compensation and related common stock issuances, net of tax	51	0	1	50	0	0	0	51	0
Contributions from noncontrolling interests	7	0	0	0	0	0	0	0	7
Other	(14)	0	0	(2)	(16)	0	0	(18)	4
Net increase (decrease) in equity	(1,781)	0	1	48	(1,746)	103	0	(1,594)	(187)
Ending balance at Dec. 31, 2020	14,583	35	1,248	24,371	(12,748)	(96)	(1,041)	11,769	2,814
Net income (loss)	1,562	0	0	0	1,517	0	0	1,517	45
Other comprehensive income (loss)	63	0	0	0	0	63	0	63	0
Dividends, Common Stock, Cash	(1,992)	0	0	0	(1,992)	0	0	(1,992)	0
Dividends and distributions to noncontrolling interests	(187)	0	0	0	0	0	0	0	(187)
Stock-based compensation and related common stock issuances, net of tax	80	0	2	78	0	0	0	80	0
Contributions from noncontrolling interests	9	0	0	0	0	0	0	0	9
Purchase of partial interest in consolidated subsidiary (Note 8)	(3)	0	0	0	0	0	0	0	(3)
Purchase of treasury stock	0
Other	(14)	0	0	0	(14)	0	0	(14)	0
Net increase (decrease) in equity	(482)	0	2	78	(489)	63	0	(346)	(136)
Ending balance at Dec. 31, 2021	14,101	35	1,250	24,449	(13,237)	(33)	(1,041)	11,423	2,678
Net income (loss)	2,117	0	0	0	2,049	0	0	2,049	68
Other comprehensive income (loss)	9	0	0	0	0	9	0	9	0
Dividends, Common Stock, Cash	(2,071)	0	0	0	(2,071)	0	0	(2,071)	0
Dividends and distributions to noncontrolling interests	(204)	0	0	0	0	0	0	0	(204)
Stock-based compensation and related common stock issuances, net of tax	96	0	3	93	0	0	0	96	0
Contributions from noncontrolling interests	18	0	0	0	0	0	0	0	18
Purchase of treasury stock	(9)	0	0	0	0	0	(9)	(9)	0
Other	(12)	0	0	0	(12)	0	0	(12)	0
Net increase (decrease) in equity	(56)	0	3	93	(34)	9	(9)	62	(118)
Ending balance at Dec. 31, 2022	$ 14,045	$ 35	$ 1,253	$ 24,542	$ (13,271)	$ (24)	$ (1,050)	$ 11,485	$ 2,560

XML

Consolidated Statement of Changes in Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of Stockholders' Equity [Abstract]
Common Stock, Dividends, Per Share, Declared	$ 1.70	$ 1.64	$ 1.60

XML

Consolidated Statement of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
OPERATING ACTIVITIES:
Net income (loss)	$ 2,117	$ 1,562	$ 198
Adjustments to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization	2,009	1,842	1,721
Provision (benefit) for deferred income taxes	431	509	108
Equity (earnings) losses	(637)	(608)	(328)
Distributions from equity-method investees (Note 8)	865	757	653
Impairment of goodwill (Note 15)	0	0	187
Impairment of equity-method investments (Note 15)	0	0	1,046
Impairment of certain assets (Note 15)	0	2	182
Net unrealized (gain) loss from derivative instruments	249	109	0
Inventory write-downs	161	15	17
Amortization of stock-based awards	73	81	52
Cash provided (used) by changes in current assets and liabilities:
Accounts receivable	(733)	(545)	(2)
Inventories	(110)	(139)	(28)
Other current assets and deferred charges	(33)	(63)	11
Accounts payable	410	643	(7)
Accrued and other current liabilities	209	58	(309)
Changes in current and noncurrent derivative assets and liabilities	94	(277)	(4)
Other, including changes in noncurrent assets and liabilities	(216)	(1)	(1)
Net cash provided (used) by operating activities	4,889	3,945	3,496
FINANCING ACTIVITIES:
Proceeds from (payments of) commercial paper – net	345	0	0
Proceeds from long-term debt	1,755	2,155	3,899
Payments of long-term debt	(2,876)	(894)	(3,841)
Proceeds from issuance of common stock	54	9	9
Common dividends paid	(2,071)	(1,992)	(1,941)
Dividends and distributions paid to noncontrolling interests	(204)	(187)	(185)
Contributions from noncontrolling interests	18	9	7
Payments for debt issuance costs	(17)	(26)	(20)
Other – net	(46)	(16)	(13)
Net cash provided (used) by financing activities	(3,042)	(942)	(2,085)
INVESTING ACTIVITIES:
Capital expenditures (1)	(2,253)	(1,239)	(1,239)
Dispositions – net	(30)	(8)	(36)
Contributions in aid of construction	12	52	37
Purchases of businesses, net of cash acquired (Note 3)	(933)	(151)	0
Purchases of and contributions to equity-method investments (Note 8)	(166)	(115)	(325)
Other – net	(5)	(4)	5
Net cash provided (used) by investing activities	(3,375)	(1,465)	(1,558)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect, Total	(1,528)	1,538	(147)
Cash and cash equivalents at beginning of year	1,680	142	289
Cash and cash equivalents at end of year	152	1,680	142
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
(1) Increases to property, plant, and equipment	(2,394)	(1,305)	(1,160)
Changes in related accounts payable and accrued liabilities	141	66	(79)
Capital expenditures	$ (2,253)	$ (1,239)	$ (1,239)

XML

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies [Text Block]

Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies

General

Unless the context clearly indicates otherwise, references in this report to “Williams,” “we,” “our,” “us,” or like terms refer to The Williams Companies, Inc. and its subsidiaries. Unless the context clearly indicates otherwise, references to “Williams,” “we,” “our,” and “us” include the operations in which we own interests accounted for as equity-method investments that are not consolidated in our financial statements. When we refer to our equity investees by name, we are referring exclusively to their businesses and operations.

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 share repurchase program does not have an expiration date. There were $9 million and no repurchases under the program in 2022 and 2021, respectively.

Description of Business

We are a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. Our operations are located in the United States and are 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, as well as corporate activities are included in Other.

Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline LLC (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 LLC (Gulfstar One) (a consolidated variable interest entity, or VIE), a 50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream), and a 60 percent equity-method investment in Discovery Producer Services LLC (Discovery). Transmission & Gulf of Mexico also includes natural gas storage facilities and pipelines providing services in north Texas.

Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in Ohio Valley Midstream LLC (Northeast JV) (a consolidated VIE) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated VIE) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a 50 percent equity-method investment in Blue Racer Midstream LLC (Blue Racer), and Appalachia Midstream Services, LLC, 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 (Appalachia Midstream Investments).

West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of east Texas and northwest Louisiana, and the Mid-Continent region which includes the Anadarko and Permian basins. This segment also includes our NGL storage facilities, an undivided 50

percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in Overland Pass Pipeline Company LLC (OPPL), a 50 percent equity-method investment in Rocky Mountain Midstream Holdings LLC (RMM), a 20 percent equity-method investment in Targa Train 7 LLC (Targa Train 7) (a nonconsolidated VIE), and a 15 percent equity-method investment in Brazos Permian II, LLC (Brazos Permian II) (a nonconsolidated VIE).

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 natural gas liquids (NGLs) on strategically positioned assets.

Basis of Presentation

Discontinued operations

Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations.

Significant risks and uncertainties

We believe that the carrying value of certain of our property, plant, and equipment and intangible assets, notably certain acquired assets accounted for as business combinations between 2012 and 2014, may be in excess of current fair value. However, the carrying value of these assets, in our judgment, continues to be recoverable. It is reasonably possible that future strategic decisions, including transactions such as monetizing assets or contributing assets to new ventures with third parties, as well as unfavorable changes in expected producer activities, could impact our assumptions and ultimately result in impairments of these assets. Such transactions or developments may also indicate that certain of our equity-method investments have experienced other-than-temporary declines in value, which could result in impairment.

Summary of Significant Accounting Policies

Principles of consolidation

The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain ventures in which we own an undivided interest. Our judgment is required to evaluate whether we control an entity. Key areas of that evaluation include:

•Determining whether an entity is a VIE (see Note 2 – Variable Interest Entities);

•Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests;

•Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether we are a VIE’s primary beneficiary;

•Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities.

We apply the equity method of accounting to investments over which we exercise significant influence but do not control. Distributions received from equity-method investees are presented in our Consolidated Statement of Cash Flows according to the nature of the distributions approach, which classifies distributions received from equity-method investees as either returns on investment (cash inflows from operating activities) or returns of

investment (cash inflows from investing activities) based on the nature of the activities of the equity-method investee that generated the distribution.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Significant estimates and assumptions include:

•Impairment assessments of investments, property, plant, and equipment, and intangible assets;

•Litigation-related contingencies;

•Environmental remediation obligations;

•Depreciation and/or amortization of long-lived assets, which are comprised of property, plant, and equipment, and intangible assets;

•Depreciation and/or amortization of equity-method investment basis differences;

•Asset retirement obligations (AROs);

•Measurement of fair value of derivatives;

•Pension and postretirement valuation variables;

•Measurement of regulatory liabilities;

•Measurement of deferred income tax assets and liabilities, including assumptions related to the realization of deferred income tax assets;

•Revenue recognition, including estimates utilized in recognition of deferred revenue;

•Purchase price accounting.

These estimates are discussed further throughout these notes.

Regulatory accounting

Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC), and their rates are established by the FERC. Therefore, we have determined that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” (ASC 980) that certain costs that would otherwise be charged to expense should be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense should be deferred as regulatory liabilities, based on the expected return to customers in future rates. Management’s expected recovery of deferred costs and return of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. We record certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refunded in future rates. Accounting for these operations that are regulated can differ from the accounting requirements for nonregulated operations. For example, for regulated operations, allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in the process of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual cost of construction under established regulatory practices; nonregulated operations are only allowed to capitalize the cost of debt funds related to construction activities, while a component for equity is prohibited. The

components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, AROs, shipper imbalance activity, fuel and power cost differentials, depreciation, negative salvage, pension and other postretirement benefits, customer tax refunds, and rate allowances for deferred income taxes at a historically higher federal income tax rate.

Our current and noncurrent regulatory asset and liability balances at December 31, 2022 and 2021 are as follows:

	December 31,
	2022		2021
	(Millions)
Current assets reported within Other current assets and deferred charges	$	138	$	111
Noncurrent assets reported within Regulatory assets, deferred charges, and other	459		415
Total regulated assets	$	597	$	526
Current liabilities reported within Accrued and other current liabilities	$	201	$	56
Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other	1,233		1,324
Total regulated liabilities	$	1,434	$	1,380

Revenue recognition

Customers in our gas pipeline businesses are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical power generators. Customers in our midstream businesses are comprised of oil and natural gas producer counterparties. Customers for our product sales are comprised of public utilities, gas marketers, and direct industrial users.

Service revenue contracts from our gas pipeline and midstream businesses contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single performance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer.

Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. For our rate-regulated gas pipeline businesses that apply ASC 980, we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, in our judgment, the construction activities do not represent an ongoing major and central operation of our gas pipeline businesses and are not within the scope of ASC Topic 606, “Revenue from Contracts with Customers”. Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset, which are referred to as Contributions in aid of construction in our Consolidated Statement of Cash Flows. For our midstream businesses, reimbursement and service contracts with customers are viewed together as providing the same commercial objective, as we have the ability to negotiate the mix of consideration between reimbursements and amounts billed over time. Accordingly, we generally recognize reimbursements of construction costs from customers on a gross basis as a contract liability separate from the associated costs included within property, plant, and equipment. The contract liability is recognized into service revenues as the underlying performance obligations are satisfied.

Service Revenues

Gas pipeline businesses: Revenues from our regulated interstate natural gas pipeline businesses, which are subject to regulation by certain state and federal authorities, including the FERC, include both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a daily or monthly reservation charge based on the pipeline or storage capacity reserved, and a commodity charge

based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or based on negotiated contractual rates, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one-month periods or less. Our performance obligations related to our interstate natural gas pipeline businesses include the following:

•Firm transportation or storage under firm transportation and storage contracts—an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities;

•Interruptible transportation or storage under interruptible transportation and storage contracts—an integrated package of services typically constituting a single performance obligation once scheduled, which includes receiving, transporting or storing (as applicable), and redelivering commodities.

In situations where, in our judgment, we consider the integrated package of services as a single performance obligation, which represents a majority of our interstate natural gas pipeline contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready performance obligation.

We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges in our interstate natural gas pipeline businesses are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refund upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.

Midstream businesses: Revenues from our non-regulated gathering, processing, transportation, and storage midstream businesses include contracts for natural gas gathering, processing, treating, compression, transportation, and other related services with contract terms that are generally long-term in nature and may extend up to the production life of the associated reservoir. Additionally, our midstream businesses generate revenues from fees charged for storing customers’ natural gas and NGLs, generally under prepaid contracted storage capacity contracts. In situations where, in our judgment, we provide an integrated package of services combined into a single performance obligation, which represents a majority of this class of contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to provide gathering, processing, transportation, storage, and related services resulting in the delivery, or redelivery in the context of storage services, of pipeline-quality natural gas and NGLs to the customer. As such, revenue is recognized at the daily completion of the integrated package of services as the integrated package represents a single performance obligation. Additionally, certain contracts in our midstream businesses contain fixed or upfront payment terms that result in the deferral of revenues until such services have been performed or such capacity has been made available.

We also earn revenues from offshore crude oil and natural gas gathering and transportation and offshore production handling. These services represent an integrated package of services and are considered a single distinct performance obligation for which we recognize revenues as the services are provided to the customer.

We generally earn a contractually stated fee per unit for the volume of product transported, gathered, processed, or stored. The rate is generally fixed; however, certain contracts contain variable rates that are subject to change based on commodity prices, levels of throughput, or an annual adjustment based on a formulaic cost of service calculation. In addition, we have contracts with contractually stated fees that decline over the contract term, such as declines based on the passage of time periods or achievement of cumulative throughput amounts. For all of our contracts, we allocate the transaction price to each performance obligation based on the judgmentally determined relative standalone selling price. The excess of consideration received over revenue recognized results in the deferral of those amounts until future periods based on a units of production or straight-line methodology as these methods appropriately match the consumption of services provided to the customer. The units of production methodology requires the use of production estimates that are uncertain and the use of judgment when developing estimates of future production volumes, thus impacting the rate of revenue recognition. Production estimates are monitored as circumstances and events warrant. Certain of our gas gathering and processing agreements have minimum volume commitments (MVC). If a customer under such an agreement fails to meet its MVC for a specified period (thus not exercising all the contractual rights to gathering and processing services within the specified period, herein referred to as “breakage”), it is obligated to pay a contractually determined fee based upon the shortfall between the actual gathered or processed volumes and the MVC for the period contained in the contract. When we conclude, based on management’s judgment, it is probable that the customer will not exercise all or a portion of its remaining rights, we recognize revenue associated with such breakage amount in proportion to the pattern of exercised rights within the respective MVC period.

Under keep-whole and percent-of-liquids processing contracts, we receive commodity consideration in the form of NGLs and take title to the NGLs at the tailgate of the plant. We recognize such commodity consideration as service revenue based on the market value of the NGLs retained at the time the processing is provided. The current market value, as opposed to the market value at the contract inception date, is used due to a combination of factors, including the fact that the volume, mix, and market price of NGL consideration to be received is unknown at the time of contract execution and is not specified in our contracts with customers. Additionally, product sales revenue (discussed below) is recognized upon the sale of the NGLs to a third party based on the sales price at the time of sale. As a result, revenue is recognized in our Consolidated Statement of Income both at the time the processing service is provided in Service revenues – commodity consideration and at the time the NGLs retained as part of the processing service are sold in Product sales. The recognition of revenue related to commodity consideration has the impact of increasing the book value of NGL inventory, resulting in higher cost of goods sold at the time of sale.

Product Sales

In the course of providing transportation services to customers of our gas pipeline businesses and gathering and processing services to customers of our midstream businesses, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs or gathering and processing agreements, respectively. Revenue is recognized from the sale of natural gas upon settlement of imbalances.

In certain instances, we purchase NGLs, crude oil, and natural gas from our oil and natural gas producer customers which we remarket. In addition, we retain NGLs as consideration in certain processing arrangements, as discussed above in the Service Revenues - Midstream businesses section. We also market natural gas and NGLs from the production at our upstream properties. We recognize revenue from the sale of these commodities when the products have been sold and delivered. Our product sales contracts are primarily short-term contracts based on prevailing market rates at the time of the transaction.

We purchase natural gas for storage when the current market price paid to buy and transport natural gas plus the cost to store and finance the natural gas is less than an estimated, forward market price that can be received in the future, resulting in positive net product sales. Commodity-based exchange-traded futures

contracts and over-the-counter (OTC) contracts are used to sell natural gas at that future price to substantially protect the natural gas revenues that will ultimately be realized when the stored natural gas is sold. Additionally, we enter into transactions to secure transportation capacity between delivery points in order to serve our customers and various markets.

The physical purchase, transportation, storage, and sale of natural gas are accounted for on a weighted-average cost or accrual basis, as appropriate, unlike the fair value basis utilized for the derivatives used to mitigate the natural gas price risk associated with the storage and transportation portfolio. Monthly demand charges are incurred for the contracted storage and transportation capacity and payments associated with asset management agreements, and these demand charges and payments are recognized in our Consolidated Statement of Income in the period they are incurred.

As we are acting as an agent for our natural gas marketing customers and engage in energy trading activities, our natural gas marketing revenues are presented net of the related costs of those activities. Prior to the 2022 integration of our legacy gas marketing operations with the acquired Sequent Acquisition operations (see Note 3 – Acquisitions), our legacy gas marketing operations were reported on a gross basis.

Contract Assets

Our contract assets primarily consist of revenue recognized under contracts containing MVC features whereby management has concluded it is probable there will be a short-fall payment at the end of the current MVC period, which typically follows the calendar year, and that a significant reversal of revenue recognized currently for the future MVC payment will not occur. As a result, our contract assets related to our future MVC payments are generally expected to be collected within the next 12 months and are included within Other current assets and deferred charges in our Consolidated Balance Sheet until such time as the MVC short-fall payments are invoiced to the customer.

Contract Liabilities

Our contract liabilities consist of advance payments primarily from midstream business customers which include construction reimbursements, prepayments, and other billings and transactions for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily based on a units of production methodology over the remaining contractual service periods, and are classified as current or noncurrent according to when such amounts are expected to be recognized. Current and noncurrent contract liabilities are included within Accrued and other current liabilities and Regulatory liabilities, deferred income, and other, respectively, in our Consolidated Balance Sheet.

Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer, when the customer pays for those goods or services, and the prevailing interest rates. We have assessed our contracts for significant financing components and determined, in our judgment, that one group of contracts entered into in contemplation of one another for certain capital reimbursements contains a significant financing component. As a result, we recognize noncash interest expense based on the effective interest method and revenue (noncash) is recognized when the underlying asset is placed into service utilizing a units of production or straight-line methodology over the life of the corresponding customer contract.

Derivative instruments and hedging activities

We are exposed to commodity price risk. We utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of energy commodities. We purchase natural gas for storage when the current market price paid

to buy and transport natural gas plus the cost to store and finance the natural gas is less than an estimated, forward market price that can be received in the future. Additionally, we enter into transactions to secure transportation capacity between delivery points in order to serve our customers and various markets. Commodity-based exchange-traded futures contracts and OTC contracts are used to capture the price differential or spread between the locations served by the capacity in order to substantially protect the natural gas revenues that will ultimately be realized when the physical flow of natural gas between receipt and delivery points occurs. Some commodity-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the natural gas marketing operations. These contracts generally meet the definition of derivatives and are typically not designated as hedges for accounting purposes. When a commodity-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed, and the contract price is recognized in the respective line item in our Consolidated Statement of Income representing the actual price of the underlying goods being delivered.

Unrealized gains and losses on physically settled commodity-related derivative contracts for commodity sales transactions are recognized in Net gain (loss) on commodity derivatives in our Consolidated Statement of Income. Realized and unrealized gains and losses on non-designated commodity-related derivative contracts for commodity sales transactions that are financially settled are reported in Net gain (loss) on commodity derivatives in our Consolidated Statement of Income. Net gains and losses on derivatives for shrink gas purchases for processing plants are reported in Net processing commodity expenses in our Consolidated Statement of Income.

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. (See Note 16 – Derivatives.)

We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Derivative assets; Regulatory assets, deferred charges, and other; Derivative liabilities; or Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet. These amounts are presented on a net basis and reflect the netting of asset and liability positions permitted under the terms of master netting arrangements and cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades.

The accounting for the changes in fair value of a commodity derivative can be summarized as follows:

Derivative Treatment	Accounting Method
Normal purchases and normal sales exception	Accrual accounting
Designated in a qualifying hedging relationship	Hedge accounting
All other derivatives	Mark-to-market accounting

We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected in our Consolidated Balance Sheet after the initial election of the exception.

We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe

the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Net gain (loss) on commodity derivatives in our Consolidated Statement of Income.

For commodity derivatives designated as a cash flow hedge, the change in fair value of the derivative is reported in Accumulated other comprehensive income (loss) (AOCI) in our Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects earnings. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in Net gain (loss) on commodity derivatives in our Consolidated Statement of Income at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by us. As of December 31, 2022 and 2021, we are not applying hedge accounting to any commodity derivative instruments.

Interest capitalized

We capitalize interest during construction on major projects with construction periods of at least 3 months and a total project cost in excess of $1 million. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds (equity AFUDC). The latter is included in Other income (expense) – net below Operating income (loss) in our Consolidated Statement of Income. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on our average interest rate on debt.

Income taxes

We include the operations of our domestic corporate subsidiaries and income from our subsidiary partnerships in our consolidated federal income tax return and also file tax returns in various foreign and state jurisdictions as required. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of our assets and liabilities. Our judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.

Earnings (loss) per common share

Basic earnings (loss) per common share in our Consolidated Statement of Income is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share in our Consolidated Statement of Income primarily includes any dilutive effect of nonvested restricted stock units and stock options. Diluted earnings (loss) per common share is calculated using the treasury-stock method.

Cash and cash equivalents

Cash and cash equivalents in our Consolidated Balance Sheet consist of highly liquid investments with original maturities of three months or less when acquired.

Accounts receivable

Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts, considering current expected credit losses using a forward-looking “expected loss” model, the financial condition of our customers, and the age of past due accounts. The majority of our trade receivable balances are due within 30 days. We monitor the credit quality of our counterparties through review of collection trends, credit ratings, and other analyses, such as bankruptcy monitoring. Financial assets from our natural gas transmission and storage business, gathering, processing and transportation business, marketing

business, and upstream operations are segregated into separate pools for evaluation due to different counterparty risks inherent in each business. Changes in counterparty risk factors could lead to reassessment of the composition of our financial assets as separate pools or the need for additional pools. We calculate our allowance for credit losses incorporating an aging method. In estimating our expected credit losses, we utilize historical loss rates over many years, which include periods of both high and low commodity prices. Commodity prices could have a significant impact on a portion of our gathering and processing and upstream counterparties’ financial health and ability to satisfy current obligations. Our expected credit loss estimate considers both internal and external forward-looking commodity price expectations, as well as counterparty credit ratings, and factors impacting their near-term liquidity. In addition, our expected credit loss estimate considers potential contractual, physical, and commercial protections and outcomes in the case of a counterparty bankruptcy. The physical location and nature of our services help to mitigate collectability concerns of our gathering and processing producer customers. Our gathering lines in many cases are physically connected to the customers’ wellheads and pads, and there may not be alternative gathering lines nearby. The construction of gathering systems is capital intensive and it would be costly for others to replicate, especially considering the depletion to date of the associated reserves. As a result, we play a critical role in getting customers’ production from the wellhead to a marketable condition and location. This tends to reduce collectability risk as our services enable producers to generate operating cash flows. Commodity price movements generally do not impact the majority of our natural gas transmission businesses customers’ financial condition.

We also provide marketing and risk management services to retail and wholesale gas marketers, utility companies, upstream producers, and industrial customers. These counterparties utilize netting agreements that enable us to net receivables and payables by counterparty upon settlement. We also net across product lines and against cash collateral received to collateralize receivable positions, provided the netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, our counterparties are settled net, they are recorded on a gross basis in our Consolidated Balance Sheet as accounts receivable and accounts payable.

We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. We do not have a material amount of significantly aged receivables at December 31, 2022 and 2021.

Inventories

Inventories in our Consolidated Balance Sheet primarily consist of natural gas in underground storage, NGLs, and materials and supplies and primarily are stated at the lower of cost or net realizable value. The cost of inventories is primarily determined using the average-cost method. Any lower of cost or net realizable value adjustments are included in Product sales (for natural gas marketing inventory as these sales are presented net of the related costs) or in Product costs for NGL inventory.

Property, plant, and equipment

Property, plant, and equipment is initially recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values.

As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply an accelerated depreciation method.

We follow the successful efforts method of accounting for our undivided interest in upstream properties. Our oil and gas producing property costs are depreciated using a units of production method.

Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation. Gains or losses from the ordinary sale or retirement of property,

plant, and equipment for nonregulated assets are primarily recorded in Other (income) expense – net included in Operating income (loss) in our Consolidated Statement of Income.

Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment.

We record a liability and increase the basis in the underlying asset for the present value of each expected future ARO at the time the liability is initially incurred, typically when the asset is acquired or constructed. For our upstream properties, the ARO is recorded based on our working interest in the underlying properties. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset as we expect to recover these amounts in future rates. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in our Consolidated Statement of Income, except for regulated entities, for which the increase in the liability results in a corresponding increase to a regulatory asset. The regulatory asset is amortized commensurate with our collection of those costs in rates.

Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium.

Intangible assets

Our intangible assets included within Intangible assets – net of accumulated amortization in our Consolidated Balance Sheet are primarily related to gas gathering, processing, and fractionation customer relationships. Our intangible assets are generally amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life.

Impairment of property, plant, and equipment, intangible assets, and investments

We evaluate our property, plant, and equipment and intangible assets for impairment when, in our judgment, events or circumstances, including probable abandonment, indicate that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes, including selling the assets in the near term or holding them for their remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment to be recognized in our consolidated financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.

For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.

We evaluate our investments for impairment when, in our judgment, events or circumstances indicate that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in our consolidated financial statements as an impairment charge.

Judgment and assumptions are inherent in our estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.

Equity-method investment basis differences

Differences between the carrying value of our equity-method investments and our underlying equity in the net assets of investees are accounted for as if the investees were consolidated subsidiaries. Equity earnings (losses) in our Consolidated Statement of Income includes our allocable share of net income (loss) of investees adjusted for any depreciation and amortization, as applicable, associated with basis differences.

Leases

We recognize a lease liability with an offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases based on the present value of the future lease payments. We have elected to combine lease and nonlease components for all classes of leased assets in our calculation of the lease liability and the offsetting right-of-use asset.

Our lease agreements require both fixed and variable periodic payments, with initial terms typically ranging from one year to 20 years. Payment provisions in certain of our lease agreements contain escalation factors which may be based on stated rates or a change in a published index at a future time. The amount by which a lease escalates based on the change in a published index, which is not known at lease commencement, is considered a variable payment and is not included in the present value of the future lease payments, which only includes those that are stated or can be calculated based on the lease agreement at lease commencement. In addition to the noncancellable periods, many of our lease agreements provide for one or more extensions of the lease agreement for periods ranging from one year in length to an indefinite number of times following the specified contract term. Other lease agreements provide for extension terms that allow us to utilize the identified leased asset for an indefinite period of time so long as the asset continues to be utilized in our operations. In consideration of these renewal features, we assess the term of the lease agreements, which includes using judgment in the determination of which renewal periods and termination provisions, when at our sole election, will be reasonably certain of being exercised. Periods after the initial term or extension terms that allow for either party to the lease to cancel the lease are not considered in the assessment of the lease term. Additionally, we have elected to exclude leases with an original term of one year or less, including renewal periods, from the calculation of the lease liability and the offsetting right-of-use asset.

We use judgment in determining the discount rate upon which the present value of the future lease payments is determined. This rate is based on a collateralized interest rate corresponding to the term of the lease agreement using company, industry, and market information available.

When permitted under our lease agreements, we may sublease certain unused office space for fixed periods that could extend up to the length of the original lease agreement.

Pension and other postretirement benefits

The funded status of each of the pension and other postretirement benefit plans is recognized separately in our Consolidated Balance Sheet as either an asset or liability. The plans’ benefit obligations and net periodic benefit costs (credits) are actuarially determined and impacted by various assumptions and estimates.

The discount rates are determined separately for each of our pension and other postretirement benefit plans based on an approach specific to our plans. The year-end discount rates are determined considering a yield curve comprised of high-quality corporate bonds and the timing of the expected benefit cash flows of each plan.

The expected long-term rates of return on plan assets are determined by combining a review of the historical returns within the portfolio, the investment strategy included in the plans’ investment policy statement, and capital

market projections for the asset classes in which the portfolio is invested, as well as the weighting of each asset class.

Unrecognized actuarial gains and losses are deferred and recorded in AOCI or, for Transco and Northwest Pipeline, as a regulatory asset or liability, until amortized as a component of net periodic benefit cost (credit). The unrecognized net actuarial losses deferred in AOCI at December 31, 2022 and 2021 were $18 million and $30 million, respectively. Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of plan assets are amortized over the participants’ average remaining future years of service, which is approximately 10 years for our pension plans and approximately 5 years for our other postretirement benefit plan.

The expected return on plan assets component of net periodic benefit cost (credit) is calculated using the market-related value of plan assets. For our pension plans, the market-related value of plan assets is equal to the fair value of plan assets adjusted to reflect the amortization of gains or losses associated with the difference between the expected and actual return on plan assets over a 5-year period. Additionally, the market-related value of assets may be no more than 110 percent or less than 90 percent of the fair value of plan assets at the beginning of the year. The market-related value of plan assets for our other postretirement benefit plan is equal to the unadjusted fair value of plan assets at the beginning of the year.

Contingent liabilities

We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable, and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.

Treasury stock

Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as Treasury stock, at cost in our Consolidated Balance Sheet. Gains and losses on the subsequent reissuance of shares are credited or charged to Capital in excess of par value in our Consolidated Balance Sheet using the average-cost method.

Cash flows from revolving credit facility and commercial paper program

Proceeds and payments related to borrowings under our revolving credit facility are reflected in the financing activities in our Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in our Consolidated Statement of Cash Flows on a net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See Note 12 – Debt and Banking Arrangements.)

XML

Variable Interest Entities

12 Months Ended

Dec. 31, 2022

Variable Interest Entity Disclosures [Abstract]

Variable Interest Entities [Text Block]

Note 2 – Variable Interest Entities

Consolidated VIEs

As of December 31, 2022, we consolidate the following VIEs:

Northeast JV

We own a 65 percent interest in the Northeast JV, a subsidiary that is a VIE due to certain of our voting rights being disproportionate to our obligation to absorb losses and substantially all of the Northeast JV’s activities being

performed on our behalf. We are the primary beneficiary because we have the power to direct the activities that most significantly impact the Northeast JV’s economic performance. The Northeast JV provides midstream services for producers in the Marcellus Shale and Utica Shale regions. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis.

Gulfstar One

We own a 51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes a proprietary floating-production system, Gulfstar FPS, and associated pipelines that provide production handling and gathering services in the eastern deepwater Gulf of Mexico. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance.

Cardinal

We own a 66 percent interest in Cardinal, a subsidiary that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner.

The following table presents amounts included in the Consolidated Balance Sheet that are only for the use or obligation of our consolidated VIEs:

	December 31,
	2022		2021
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	49	$	78
Trade accounts and other receivables – net	136		132
Inventories	4		3
Other current assets and deferred charges	7		7
Property, plant, and equipment – net	5,154		5,295
Intangible assets – net of accumulated amortization	2,158		2,267
Regulatory assets, deferred charges, and other	29		20
Accounts payable	(76)		(61)
Accrued and other current liabilities	(34)		(29)
Regulatory liabilities, deferred income, and other	(275)		(287)

Nonconsolidated VIEs

Targa Train 7

We own a 20 percent interest in Targa Train 7, which provides fractionation services at Mont Belvieu, Texas, and is a VIE due primarily to our limited participating rights as the minority equity holder. At December 31, 2022, the carrying value of our investment in Targa Train 7 was $46 million. Our maximum exposure to loss is limited to the carrying value of our investment.

Brazos Permian II

We own a 15 percent interest in Brazos Permian II, which provides gathering and processing services in the Delaware basin and is a VIE due primarily to our limited participating rights as the minority equity holder. At December 31, 2022, the carrying value of our investment in Brazos Permian II was $16 million. Our maximum exposure to loss is limited to the carrying value of our investment.

XML

Acquisitions

12 Months Ended

Dec. 31, 2022

Business Combinations [Abstract]

Acquisitions [Text Block]

Note 3 – Acquisitions

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 (Trace) for $972 million of cash funded with cash on hand and proceeds from issuance of commercial paper (Trace Acquisition). 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.

During the period from the acquisition date of April 29, 2022 to December 31, 2022, the operations acquired in the Trace Acquisition contributed Revenues of $148 million and Modified EBITDA (as defined in Note 18 – Segment Disclosures) of $73 million.

Acquisition-related costs for the Trace Acquisition for the period from the acquisition date of April 29, 2022 to December 31, 2022 of $8 million are reported within our West segment and included in Selling, general, and administrative expenses in our Consolidated Statement of Income.

We accounted for the Trace Acquisition as a business combination, which requires, among other things, that identifiable assets acquired and liabilities assumed be recognized at their acquisition date fair values. The valuation techniques used consisted of the income approach (excess earnings method) for valuation of intangible assets and depreciated replacement costs for property, plant, and equipment.

The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in the West segment, and liabilities assumed at April 29, 2022. The fair value of accounts receivable acquired equals contractual amounts receivable.

	(Millions)
Cash and cash equivalents	$	39
Trade accounts and other receivables – net	18
Property, plant, and equipment – net	448
Intangible assets – net of accumulated amortization	472
Other noncurrent assets	20
Total assets acquired	$	997
Accounts payable	$	12
Accrued and other current liabilities	5
Other noncurrent liabilities	8
Total liabilities assumed	$	25
Net assets acquired	$	972

Intangible assets

Intangible assets recognized in the Trace Acquisition are related to contractual customer relationships from gas gathering agreements with our customers. The basis for determining the value of these intangible assets is estimated future net cash flows to be derived from acquired contractual customer relationships discounted using a risk-adjusted

discount rate. These intangible assets are being amortized on a straight-line basis over an initial period of 20 years which represents the term over which the contractual customer relationships are expected to contribute to our cash flows. Approximately 2 percent of the expected future revenues from these contractual customer relationships are impacted by our ability and intent to renew or renegotiate existing customer contracts. We expense costs incurred to renew or extend the terms of our gas gathering contracts with customers. Based on the estimated future revenues during the current contract periods (as estimated at the time of the acquisition), the weighted-average period prior to the next renewal or extension of the existing contractual customer relationships is approximately 19 years. See Note 10 – Intangible Assets.

Sequent Acquisition

On July 1, 2021, we closed on the acquisition of 100 percent of Sequent Energy Management, L.P. and Sequent Energy Canada, Corp (Sequent Acquisition). Total consideration for this acquisition was $159 million, which included $109 million related to working capital.

Operations acquired in the Sequent Acquisition focus on risk management and the marketing, trading, storage, and transportation of natural gas for a diverse set of natural gas and electric utilities, municipalities, power generators, and producers, as well as moving gas to markets through transportation and storage agreements on strategically positioned assets, including our Transco system. The purpose of the Sequent Acquisition was to expand our natural gas marketing activities as well as optimize our pipeline and storage capabilities with expansions into new markets to reach incremental gas-fired power generation, liquified natural gas exports, and future renewable natural gas and other emerging opportunities.

During the period from the acquisition date of July 1, 2021 to December 31, 2021, results for the operations acquired in the Sequent Acquisition included net Product sales of $(43) million (including $80 million of purchases from affiliates), Net gain (loss) on commodity derivatives of $(43) million, and unfavorable Modified EBITDA of $112 million. Both the Revenues and Modified EBITDA amounts reflect a net unrealized loss on commodity derivatives in Net gain (loss) on commodity derivatives of $(109) million for the period.

Acquisition-related costs for the Sequent Acquisition for the period from the acquisition date of July 1, 2021 to December 31, 2021 of $5 million are reported within our Gas & NGL Marketing Services segment and were included in Selling, general, and administrative expenses in our Consolidated Statement of Income for the year ended December 31, 2021.

We accounted for the Sequent Acquisition as a business combination. The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in the Gas & NGL Marketing Services segment, and liabilities assumed at July 1, 2021. The fair value of accounts receivable acquired equals contractual amounts receivable. The fair value of the intangible assets was measured using an income approach. The fair value of the inventory acquired was based on the market price of the natural gas in underground storage at the acquisition date. See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk for the valuation techniques used to measure fair value of derivative assets and liabilities.

	(Millions)
Cash and cash equivalents	$	8
Trade accounts and other receivables – net	498
Inventories	121
Derivative assets	57
Other current assets and deferred charges	4
Property, plant, and equipment – net	5
Intangible assets – net of accumulated amortization	306
Other noncurrent assets	3
Commodity derivatives included in other noncurrent assets	49
Total assets acquired	$	1,051
Accounts payable	$	514
Derivative liabilities	116
Accrued and other current liabilities	46
Other noncurrent liabilities	1
Commodity derivatives included in other noncurrent liabilities	215
Total liabilities assumed	$	892
Net assets acquired	$	159

Accounts receivable and accounts payable

The operations acquired in the Sequent Acquisition provide services to retail and wholesale gas marketers, utility companies, upstream producers, and industrial customers. See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies for our policy regarding netting receivables and payables.

Intangible assets

Intangible assets are primarily related to transportation and storage capacity contracts. The basis for determining the value of these intangible assets was estimated future net cash flows to be derived from acquired transportation and storage capacity contracts that provide future economic benefits due to their market location, discounted using an industry weighted-average cost of capital. This intangible asset is being amortized based on the expected benefit period over which the underlying contracts are expected to contribute to our cash flows ranging from 1 year to 8 years. As a result, we expect a significant portion of the amortization to be recognized within the first few years of this range. See Note 10 – Intangible Assets.

Commodity derivatives

We are exposed to commodity price risk. To manage this volatility, we use various contracts in our marketing and trading activities that generally meet the definition of derivatives. We enter into commodity-related derivatives to economically hedge exposures to natural gas and retain exposure to price changes that can, in a volatile energy market, be material and can adversely affect our results of operations; see Note 1 – General, Description of

Business, Basis of Presentation, and Summary of Significant Accounting Policies for our accounting policy for derivatives.

Supplemental Pro Forma

The following pro forma Revenues and Net income (loss) attributable to The Williams Companies, Inc. in 2022, 2021, and 2020, are presented as if the Trace Acquisition had been completed on January 1, 2021, and the Sequent Acquisition had been completed on January 1, 2020. These pro forma amounts are not necessarily indicative of what the actual results would have been if the Trace Acquisition and Sequent Acquisition had in fact occurred on the dates or for the periods indicated, nor do they purport to project Revenues or Net income (loss) attributable to The Williams Companies, Inc. for any future periods or as of any date. These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result from the transaction or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements.

	Year Ended December 31, 2022
	As Reported		Pro Forma Trace (1)				Pro Forma Combined
	(Millions)
Revenues	$	10,965	$	45			$	11,010
Net income (loss) attributable to The Williams Companies, Inc.	2,049		18				2,067
	Year Ended December 31, 2021
	As Reported		Pro Forma Trace		Pro Forma Sequent (2)		Pro Forma Combined
	(Millions)
Revenues	$	10,627	$	118	$	188	$	10,933
Net income (loss) attributable to The Williams Companies, Inc.	1,517		42		4		1,563
	Year Ended December 31, 2020
	As Reported				Pro Forma Sequent		Pro Forma Combined
	(Millions)
Revenues	$	7,719			$	74	$	7,793
Net income (loss) attributable to The Williams Companies, Inc.	211				(13)		198

(1)Excludes results from operations acquired in the Trace Acquisition for the period beginning on the acquisition date of April 29, 2022, as these results are included in the amounts as reported.

(2)Excludes results from operations acquired in the Sequent Acquisition for the period beginning on the acquisition date of July 1, 2021, as these results are included in the amounts as reported.

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 (NorTex Asset Purchase) for approximately $424 million. These assets are included in the Transmission & Gulf of Mexico segment.

XML

Related Party Transactions

12 Months Ended

Dec. 31, 2022

Related Party Transactions [Abstract]

Related Party Transactions [Text Block]

Note 4 – Related Party Transactions

Transactions with Equity-Method Investees

We have expenses associated with our equity-method investees of $1.346 billion, $948 million, and $348 million for 2022, 2021, and 2020, respectively in our Consolidated Statement of Income. Substantially all of these expenses are included in Product costs. We also have revenue from our equity-method investees of $76 million, $46 million, and $26 million for 2022, 2021, and 2020, respectively. In addition, we have $17 million and $9 million included in Accounts receivable and $87 million and $89 million included in Accounts payable in our Consolidated Balance Sheet with our equity-method investees at December 31, 2022 and 2021, respectively.

We have operating agreements with certain equity-method investees. These operating agreements typically provide for reimbursement or payment to us for certain direct operational payroll and employee benefit costs, materials, supplies, and other charges and also for management services. The total charges to equity-method investees for these fees are $65 million, $70 million, and $79 million for 2022, 2021, and 2020, respectively.

Board of Directors

Two members of our Board of Directors are also executive officers at certain of our counterparties. We recorded $180 million in Product sales and $86 million in Product costs in our Consolidated Statement of Income from these companies for the purchase and sale of natural gas for 2022.

XML

Revenue Recognition

12 Months Ended

Dec. 31, 2022

Revenue Recognition [Abstract]

Revenue Recognition [Text Block]

Note 5 – Revenue Recognition

Revenue by Category

The following table presents our revenue disaggregated by major service line:

	Transco		Northwest Pipeline		Gulf of Mexico Midstream and Storage		Northeast Midstream		West Midstream		Gas & NGL Marketing Services		Other		Eliminations		Total
	(Millions)
2022
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	2,696	$	443	$	—	$	—	$	—	$	—	$	—	$	(72)	$	3,067
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		365		1,395		1,476		—		—		(164)		3,072
Commodity consideration	—		—		64		14		182		—		—		—		260
Other	10		—		27		233		54		3		—		(19)		308
Total service revenues	2,706		443		456		1,642		1,712		3		—		(255)		6,707
Product sales	179		—		251		134		841		10,768		706		(1,813)		11,066
Total revenues from contracts with customers	2,885		443		707		1,776		2,553		10,771		706		(2,068)		17,773
Other revenues (1)	24		4		10		26		8		7,929		(55)		(11)		7,935
Other adjustments (2)	—		—		—		—		—		(15,467)		—		724		(14,743)
Total revenues	$	2,909	$	447	$	717	$	1,802	$	2,561	$	3,233	$	651	$	(1,355)	$	10,965
2021
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	2,547	$	441	$	—	$	—	$	—	$	—	$	—	$	(33)	$	2,955
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		344		1,308		1,184		—		—		(130)		2,706
Commodity consideration	—		—		52		7		179		—		—		—		238
Other	10		—		22		195		52		3		1		(19)		264
Total service revenues	2,557		441		418		1,510		1,415		3		1		(182)		6,163
Product sales	88		—		269		99		643		6,404		333		(1,215)		6,621
Total revenues from contracts with customers	2,645		441		687		1,609		2,058		6,407		334		(1,397)		12,784
Other revenues (1)	10		3		8		25		(32)		2,632		11		(13)		2,644
Other adjustments (2)	—		—		—		—		—		(4,828)		—		27		(4,801)
Total revenues	$	2,655	$	444	$	695	$	1,634	$	2,026	$	4,211	$	345	$	(1,383)	$	10,627

	Transco		Northwest Pipeline		Gulf of Mexico Midstream and Storage		Northeast Midstream		West Midstream		Gas & NGL Marketing Services		Other		Eliminations		Total
	(Millions)
2020
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	2,404	$	449	$	—	$	—	$	—	$	—	$	—	$	(7)	$	2,846
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		348		1,279		1,226		—		—		(97)		2,756
Commodity consideration	—		—		21		7		101		—		—		—		129
Other	10		—		27		164		35		32		1		(16)		253
Total service revenues	2,414		449		396		1,450		1,362		32		1		(120)		5,984
Product sales	80		—		114		57		152		1,602		—		(336)		1,669
Total revenues from contracts with customers	2,494		449		510		1,507		1,514		1,634		1		(456)		7,653
Other revenues (1)	10		—		9		22		9		(3)		33		(14)		66
Total revenues	$	2,504	$	449	$	519	$	1,529	$	1,523	$	1,631	$	34	$	(470)	$	7,719

______________________________

(1)Revenues not derived from contracts with customers primarily consist of physical product sales related to derivative contracts, realized and unrealized gains and losses associated with our derivative contracts, which are reported in Net gain (loss) on commodity derivatives in the Consolidated Statement of Income, management fees that we receive for certain services we provide to operated equity-method investments, and leasing revenues associated with our headquarters building.

(2)Other adjustments reflect certain costs of Gas & NGL Marketing Services’ risk management activities. As we are acting as agent for natural gas marketing customers or engage in energy trading activities, the resulting revenues are presented net of the related costs of those activities in the Consolidated Statement of Income (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).

Contract Assets

The following table presents a reconciliation of our contract assets:

	Year Ended December 31,
	2022		2021
	(Millions)
Balance at beginning of year	$	22	$	12
Revenue recognized in excess of amounts invoiced	208		184
Minimum volume commitments invoiced	(201)		(174)
Balance at end of year	$	29	$	22

Contract Liabilities

The following table presents a reconciliation of our contract liabilities:

	Year Ended December 31,
	2022		2021
	(Millions)
Balance at beginning of year	$	1,126	$	1,209
Payments received and deferred	180		116
Significant financing component	9		10
Contract liability acquired	2		1
Recognized in revenue	(274)		(210)
Balance at end of year	$	1,043	$	1,126

Remaining Performance Obligations

Remaining performance obligations primarily include reservation charges on contracted capacity for our gas pipeline firm transportation contracts with customers, storage capacity contracts, long-term contracts containing minimum volume commitments associated with our midstream businesses, and fixed payments associated with offshore production handling. For our interstate natural gas pipeline businesses, remaining performance obligations reflect the rates for such services in our current FERC tariffs for the life of the related contracts; however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes are not currently known.

Our remaining performance obligations exclude variable consideration, including contracts with variable consideration for which we have elected the practical expedient for consideration recognized in revenue as billed. Certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation amounts as of December 31, 2022, do not consider potential future performance obligations for which the renewal has not been exercised and exclude contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service. Consideration received prior to December 31, 2022, that will be recognized in future periods is also excluded from our remaining performance obligations and is instead reflected in contract liabilities.

The following table presents the amount of the contract liabilities balance expected to be recognized as revenue when performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2022.

	Contract Liabilities		Remaining Performance Obligations
	(Millions)
2023 (one year)	$	142	$	3,643
2024 (one year)	122		3,388
2025 (one year)	117		3,149
2026 (one year)	112		2,520
2027 (one year)	101		2,415
Thereafter	449		14,675
Total	$	1,043	$	29,790

XML

Provision (Benefit) for Income Taxes

12 Months Ended

Dec. 31, 2022

Income Tax Disclosure [Abstract]

Provision (Benefit) for Income Taxes [Text Block]

Note 6 – Provision (Benefit) for Income Taxes

The Provision (benefit) for income taxes includes:

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Current:
Federal	$	(25)	$	(1)	$	(29)
State	19		3		—
	(6)		2		(29)
Deferred:
Federal	424		421		98
State	7		88		10
	431		509		108
Provision (benefit) for income taxes	$	425	$	511	$	79

Reconciliations from the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes are as follows:

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Provision (benefit) at statutory rate	$	534	$	435	$	58
Increases (decreases) in taxes resulting from:
State income taxes (net of federal benefit)	113		71		6
State deferred income tax rate change	(92)		—		—
Federal valuation allowance	(70)		3		1
Federal settlements	(45)		—		—
Impact of nontaxable noncontrolling interests	(14)		(9)		3
Other – net	(1)		11		11
Provision (benefit) for income taxes	$	425	$	511	$	79

Income (loss) before income taxes includes less than $1 million of foreign income in 2022, and $2 million and $1 million of foreign loss in 2021 and 2020, respectively.

The State deferred income tax rate change benefit of $92 million is related to a decrease in our estimate of the deferred state income tax rate (net of federal effect) driven primarily by the enacted decline in the Pennsylvania state income tax rate over the next several years.

During the course of audits of our business by domestic and foreign tax authorities, we frequently face challenges regarding the amount of taxes due. These challenges include questions regarding the timing and amount of deductions and the allocation of income among various tax jurisdictions. In evaluating the liability associated with our various filing positions, we apply the two-step process of recognition and measurement. In association with this liability, we record an estimate of related interest and tax exposure as a component of our tax provision. The impact of this accrual is included within Other – net in our reconciliation of the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes.

Significant components of Deferred income tax liabilities are as follows:

	December 31,
	2022		2021
	(Millions)
Gross deferred income tax liabilities:
Property, plant and equipment	$	3,171	$	2,777
Investments	1,784		1,669
Other	138		154
Total gross deferred income tax liabilities	5,093		4,600
Gross deferred income tax assets:
Accrued liabilities	1,108		872
Foreign tax credits	91		140
Federal loss carryovers	730		879
State losses and credits	356		421
Other	121		132
Total gross deferred income tax assets	2,406		2,444
Less valuation allowance	200		297
Net deferred income tax assets	2,206		2,147
Deferred income tax liabilities	$	2,887	$	2,453

The valuation allowance at December 31, 2022 and 2021 serves to reduce the available deferred income tax assets to an amount that will, more likely than not, be realized. We considered all available positive and negative evidence, which incorporates available tax planning strategies, and management’s estimate of future reversals of existing taxable temporary differences, and have determined that a portion of our deferred income tax assets related to the Foreign tax credits and State losses and credits may not be realized. In 2022, we released $70 million of valuation allowance upon determining we expect to utilize additional foreign tax credits prior to expiration between 2024 and 2025. The amounts presented in the table above are, with respect to state items, before any federal benefit. The change from prior year for the State losses and credits reflects increases in losses and credits generated in the current and prior years less losses and/or credits utilized in the current year. We have loss and credit carryovers in multiple state taxing jurisdictions. These attributes generally expire between 2023 and 2041 with some carryovers having indefinite carryforward periods.

Federal loss carryovers at the end of 2022 include deferred tax assets on net operating loss carryovers of $705 million with no expiration date. Deferred tax assets on charitable contributions of $25 million are expected to be utilized by us prior to expiring between 2023 and 2027.

Cash payments for income taxes (net of refunds) were $13 million in 2022. Cash refunds for income taxes (net of payments) were $45 million and $40 million in 2021 and 2020, respectively.

During the second quarter of 2022, we finalized settlements for 2011 through 2014 on certain contested matters with the Internal Revenue Service (IRS) that resulted in a 2022 year-to-date tax benefit of approximately $45 million. In 2022, we received cash refunds related to these settlements totaling $7 million.

We recognize related interest and penalties as a component of Provision (benefit) for income taxes. Total interest and penalties recognized as part of income tax provision were benefits of $3 million in 2022 and $1 million in each of 2021 and 2020. There are no interest or penalties relating to uncertain tax positions accrued as of December 31, 2022 and $4 million of interest was accrued as of December 31, 2021.

Consolidated U.S. Federal income tax returns are open to IRS examination for years after 2017. As of December 31, 2022, examination of 2018 is currently in process, with the statute extended to September 30, 2023. We do not expect material changes in our financial position resulting from this examination. The statute of limitations for most states expires one year after expiration of the IRS statute.

XML

Employee Benefit Plans

12 Months Ended

Dec. 31, 2022

Retirement Benefits [Abstract]

Employee Benefit Plans [Text Block]

Note 7 – Employee Benefit Plans

Pension Plans

We have noncontributory defined benefit pension plans for eligible employees hired prior to January 1, 2019. Eligible employees earn compensation credits based on a cash balance formula. As of January 1, 2020, certain active employees are no longer eligible to receive compensation credits.

Other Postretirement Benefits

We provide subsidized retiree medical benefits to a closed group of participants as well as retiree life insurance benefits to eligible participants. Medical benefits for Medicare eligible participants are paid through contributions to health reimbursement accounts. Benefits for all other participants are provided through a self-insured medical plan, which includes participant contributions and contains other cost-sharing features such as deductibles, co-payments, and co-insurance.

Defined Contribution Plan

We have a defined contribution plan for the benefit of substantially all employees. Plan participants may contribute a portion of their compensation on a pre-tax or after-tax basis. Generally, we match employee contributions up to 6 percent of eligible compensation. Additionally, eligible active employees that do not receive compensation credits under the defined benefit pension plan are eligible for an additional annual fixed-percentage contribution made by us to the defined contribution plan. Our contributions charged to expense were $53 million in 2022, $45 million in 2021, and $42 million in 2020.

Funded Status

The following table presents the changes in benefit obligations and plan assets for pension benefits and other postretirement benefits for the years indicated:

	Pension Benefits				Other Postretirement Benefits
	2022		2021		2022		2021
	(Millions)
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,133	$	1,183	$	200	$	220
Service cost	28		30		1		1
Interest cost	31		28		6		5
Plan participants’ contributions	—		—		2		2
Benefits paid	(78)		(83)		(12)		(14)
Net actuarial loss (gain) (1)	(162)		(21)		(45)		(14)
Settlements	(12)		(4)		—		—
Net increase (decrease) in benefit obligation	(193)		(50)		(48)		(20)
Benefit obligation at end of year	940		1,133		152		200
Change in plan assets:
Fair value of plan assets at beginning of year	1,336		1,357		287		278
Actual return on plan assets	(132)		62		(27)		16
Employer contributions	3		4		3		5
Plan participants’ contributions	—		—		2		2
Benefits paid	(78)		(83)		(12)		(14)
Settlements	(12)		(4)		—		—
Net increase (decrease) in fair value of plan assets	(219)		(21)		(34)		9
Fair value of plan assets at end of year	1,117		1,336		253		287
Funded status — overfunded (underfunded)	$	177	$	203	$	101	$	87
Amounts recognized in the Consolidated Balance Sheet:
Noncurrent assets	$	201	$	229	$	105	$	91
Current liabilities	(2)		(3)		(4)		(4)
Noncurrent liabilities	(22)		(23)		—		—
Funded status — overfunded (underfunded)	$	177	$	203	$	101	$	87
Accumulated benefit obligation	$	930	$	1,118

____________

(1)    2022 amounts are due primarily to the following factors: Pension benefits - discount rate assumptions, partially offset by change in interest crediting rate assumption; Other Postretirement Benefits - discount rate assumption. 2021 amounts are due primarily to the following factors: Pension Benefits - discount rate assumptions, partially offset by experience-related items; Other Postretirement Benefits - discount rate assumption and experience-related items.

The following table summarizes information for pension plans with obligations in excess of plan assets at December 31.

	2022		2021
	(Millions)
Projected benefit obligation	$	24	$	26
Accumulated benefit obligation	22		22
Fair value of plan assets	—		—

Pre-tax amounts recognized in Accumulated other comprehensive income (loss) at December 31 are as follows:

	Pension Benefits				Other Postretirement Benefits
	2022		2021		2022		2021
	(Millions)
Net actuarial gain (loss)	$	(45)	$	(46)	$	18	$	4

Additionally, as of December 31, 2022 and 2021, we have $130 million and $150 million, respectively, of pension and other postretirement plan amounts included in regulatory liabilities associated with our gas pipeline companies.

Net Periodic Benefit Cost (Credit)

Net periodic benefit cost (credit) for the years ended December 31 consist of the following:

	Pension Benefits						Other Postretirement  Benefits
	2022		2021		2020		2022		2021		2020
	(Millions)
Components of net periodic benefit cost (credit):
Service cost	$	28	$	30	$	31	$	1	$	1	$	1
Interest cost	31		28		36		6		5		7
Expected return on plan assets	(44)		(43)		(53)		(10)		(10)		(11)
Amortization of net actuarial loss	12		14		21		—		—		—
Net actuarial loss from settlements	3		1		9		—		—		—
Reclassification to regulatory liability	—		—		—		1		2		2
Net periodic benefit cost (credit) (1)	$	30	$	30	$	44	$	(2)	$	(2)	$	(1)

____________

(1)    Components other than Service cost are included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Income.

Items Recognized in Other Comprehensive Income (Loss)

Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) before taxes for the years ended December 31 consist of the following:

	Pension Benefits						Other Postretirement  Benefits
	2022		2021		2020		2022		2021		2020
	(Millions)
Net actuarial gain (loss) arising during the year	$	(14)	$	40	$	112	$	14	$	29	$	(4)
Amortization of net actuarial loss	12		14		21		—		—		—
Net actuarial loss from settlements	3		1		9		—		—		—
Total recognized in Other comprehensive income (loss)	$	1	$	55	$	142	$	14	$	29	$	(4)

Key Assumptions

The weighted-average assumptions utilized to determine benefit obligations and Net periodic benefit cost (credit) as of December 31 are as follows:

	Pension Benefits						Other Postretirement  Benefits
	2022		2021		2020		2022		2021		2020
Benefit obligations:
Discount rate	5.16	%	2.82	%	2.45	%	5.20	%	2.93	%	2.59	%
Rate of compensation increase	3.58		3.67		3.76		N/A		N/A		N/A
Cash balance interest crediting rate	3.50		3.00		3.00		N/A		N/A		N/A
Net periodic benefit cost (credit):
Discount rate	2.84	%	2.45	%	3.08	%	2.93	%	2.59	%	3.27	%
Expected long-term rate of return on plan assets	3.81		3.69		4.67		3.67		3.61		4.39
Rate of compensation increase	3.67		3.76		3.68		N/A		N/A		N/A
Cash balance interest crediting rate	3.00		3.00		3.50		N/A		N/A		N/A

We use mortality tables issued by the Society of Actuaries to measure the benefit obligations.

The assumed health care cost trend rate for 2023 is 6.8 percent. This rate decreases to 4.5 percent by 2032.

Plan Assets

The plans’ investment objectives include a framework to manage the volatility of the plans’ funded status and minimize future cash contributions. The plans follow a policy of diversifying the investments across various asset classes, strategies, and investment managers.

The investment policy for the pension plans includes target asset allocation percentages as well as permitted and prohibited investments designed to mitigate risks associated with investing. The December 31, 2022, target asset allocation was 25 percent equity securities and 75 percent fixed income securities, including investments in equity and fixed income mutual funds, commingled investment funds, and separate accounts.

The fair values of our pension and other postretirement benefits plan assets by asset class at December 31 are as follows: 

	2022
	Pension Benefits						Other Postretirement Benefits
	Level 1 (1)		Level 2 (2)		Total		Level 1 (1)		Level 2 (2)		Total
	(Millions)
Cash management funds	$	45	$	—	$	45	$	105	$	—	$	105
Government debt securities	58		18		76		8		3		11
Corporate debt securities	—		284		284		—		39		39
Other	1		4		5		—		—		—
	$	104	$	306	410		$	113	$	42	155
Commingled investment funds (3):
Equities					273						38
Fixed income					434						60
Total assets at fair value					$	1,117					$	253

	2021
	Pension Benefits						Other Postretirement Benefits
	Level 1 (1)		Level 2 (2)		Total		Level 1 (1)		Level 2 (2)		Total
	(Millions)
Cash management funds	$	37	$	—	$	37	$	14	$	—	$	14
Equity securities	42		19		61		39		10		49
Government debt securities	99		28		127		13		4		17
Corporate debt securities	—		350		350		—		47		47
Mutual fund - Municipal bonds	—		—		—		59		—		59
Other	(3)		2		(1)		(1)		—		(1)
	$	175	$	399	574		$	124	$	61	185
Commingled investment funds (3):
Equities					288						39
Fixed income					474						63
Total assets at fair value					$	1,336					$	287

____________

(1)    Level 1 includes assets with fair values based on quoted prices in active markets for identical assets. Cash management funds, equity securities traded on U.S. exchanges, U.S. Treasury securities, and mutual funds are included in this level.

(2)    Level 2 includes assets with fair values determined by using significant other observable inputs. This level includes equity securities traded on active foreign exchanges and fixed income securities, other than U.S. Treasury securities, that are valued primarily using pricing models which incorporate observable inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads.

(3)    The commingled investment funds are measured at fair value using net asset value per share. Certain standard withdrawal restrictions generally apply, which may include redemption notification period restrictions ranging from 1 day to 15 days.

Plan Benefit Payments and Employer Contributions

Following are the expected benefit payments, which reflect the same assumptions previously discussed and future service as appropriate.

	Pension Benefits		Other Postretirement Benefits
	(Millions)
2023	$	84	$	13
2024	83		13
2025	84		12
2026	81		12
2027	80		11
2028-2032	389		52

In 2023, we expect to contribute approximately $1 million to our pension plans and approximately $4 million to our other postretirement benefit plan.

XML

Investing Activities

12 Months Ended

Dec. 31, 2022

Investments [Abstract]

Investing Activities [Text Block]

Note 8 – Investing Activities

Investments

	Ownership Interest at December 31, 2022	December 31,
		2022		2021
		(Millions)
Equity method:
Appalachia Midstream Investments	(1)	$	2,975	$	3,056
RMM	50%	395		401
OPPL	50%	386		388
Blue Racer	50%	383		377
Discovery	60%	345		328
Gulfstream	50%	220		215
Laurel Mountain	69%	205		226
Other	Various	139		130
		5,048		5,121
Other		17		6
		$	5,065	$	5,127

___________

(1)Includes equity-method investments in multiple gathering systems in the Marcellus Shale region with an approximate average 66 percent interest.

Basis differential

The carrying value of our Appalachia Midstream Investments exceeds our portion of the underlying net assets by approximately $1.1 billion and $1.2 billion at December 31, 2022 and 2021, respectively. These differences were assigned at the acquisition date to property, plant, and equipment and customer relationship intangible assets. Certain of our other equity-method investments have a carrying value less than our portion of the underlying equity in the net assets primarily due to other than temporary impairments that we have recognized but that were not required to be recognized in the investees’ financial statements. These differences total approximately $1.1 billion and $1.2 billion at December 31, 2022 and 2021, respectively, and were assigned to property, plant, and equipment and customer relationship intangible assets. Differences in the carrying value of our equity-method investments and

our portion of the equity in the underlying net assets are generally amortized over the remaining useful lives of the associated underlying assets and included in Equity earnings (losses) within our Consolidated Statement of Income.

Purchases of and contributions to equity-method investments

We generally fund our portion of significant expansion or development projects of these investees through additional capital contributions. These transactions increased the carrying value of our investments and included:

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Appalachia Midstream Investments	$	83	$	84	$	116
Discovery	41		—		—
Cardinal Pipeline Company, LLC	16		—		—
Gulfstream	14		26		3
Blue Racer (1)	—		3		157
Other	12		2		49
	$	166	$	115	$	325

___________

(1)See following discussion in the section Acquisition of additional interests in BRMH below.

Acquisition of additional interests in BRMH

As of December 31, 2019, we effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent interest in Blue Racer Midstream Holdings, LLC (BRMH), whose primary asset is a 50 percent interest in Blue Racer. In November 2020, we paid $157 million, net of cash acquired, to acquire an additional 41 percent ownership interest in BRMH before acquiring the remaining interest of BRMH in September 2021. As such, we control and consolidate BRMH, reporting the 50 percent interest in Blue Racer as an equity-method investment. Since substantially all of the fair value of the BRMH assets acquired is concentrated in a single asset, the investment in Blue Racer, and we previously held a noncontrolling interest in BRMH, we recorded the November 2020 and September 2021 additional purchases of interests as asset acquisitions. Prior to November 2021 BRMH was named Caiman Energy II, LLC and was accounted for as an equity-method investment.

Dividends and distributions

The organizational documents of entities in which we have an equity-method investment generally require distribution of available cash to members on at least a quarterly basis. These transactions reduced the carrying value of our investments and included:

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Appalachia Midstream Investments	$	415	$	433	$	357
Laurel Mountain	112		33		31
Gulfstream	89		90		93
RMM	52		45		39
Blue Racer (1)	49		47		47
Discovery	49		44		21
OPPL	34		26		50
Other	65		39		15
	$	865	$	757	$	653

___________

(1)See previous discussion in the section Acquisition of additional interests in BRMH above.

Equity Earnings (Losses)

Equity earnings (losses) in 2020 includes a $78 million loss associated with the first-quarter full impairment of goodwill recognized by our investee RMM, which was allocated entirely to our member interest per the terms of the membership agreement. Also included in 2020 are losses of $11 million, $26 million, and $10 million for our share of asset impairments at Laurel Mountain, Appalachia Midstream Investments, and Blue Racer, respectively.

Impairments of Equity-Method Investments

See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk for information regarding impairments of our equity-method investments of $1,046 million for 2020.

Summarized Financial Position and Results of Operations of All Equity-Method Investments

	December 31,
	2022		2021
	(Millions)
Assets (liabilities):
Current assets	$	964	$	743
Noncurrent assets	12,701		13,211
Current liabilities	(632)		(435)
Noncurrent liabilities	(3,789)		(3,774)

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Gross revenue	$	5,520	$	4,688	$	2,625
Operating income	1,268		1,191		508
Net income	1,102		1,006		459

XML

Property, Plant, and Equipment

12 Months Ended

Dec. 31, 2022

Property, Plant and Equipment [Abstract]

Property, Plant, and Equipment [Text Block]

Note 9 – Property, Plant, and Equipment

The following table presents nonregulated and regulated Property, plant, and equipment – net as presented on the Consolidated Balance Sheet for the years ended:

	Estimated Useful Life  (1) (Years)	Depreciation Rates (1) (%)	December 31,
			2022		2021
			(Millions)
Nonregulated:
Natural gas gathering and processing facilities	5 - 40		$	19,163	$	18,203
Construction in progress	Not applicable		997		331
Oil and gas properties	Units of production		874		572
Other	0 - 45		2,998		2,649
Regulated:
Natural gas transmission facilities		1.25 - 7.13	19,521		19,201
Construction in progress	Not applicable	Not applicable	708		475
Other	5 - 45	0.00 - 33.33	2,796		2,753
Total property, plant, and equipment, at cost			47,057		44,184
Accumulated depreciation and amortization			(16,168)		(14,926)
Property, plant, and equipment — net			$	30,889	$	29,258

__________

(1)    Estimated useful life and depreciation rates are presented as of December 31, 2022. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC.

Depreciation and amortization expense for Property, plant, and equipment – net was $1.498 billion, $1.496 billion, and $1.393 billion in 2022, 2021, and 2020, respectively.

Regulated Property, plant, and equipment – net includes approximately $428 million and $468 million at December 31, 2022 and 2021, respectively, related to amounts in excess of the original cost of the regulated facilities within our gas pipeline businesses as a result of our prior acquisitions. This amount is being amortized over 40 years using the straight-line amortization method. Current FERC policy does not permit recovery through rates for amounts in excess of original cost of construction.

Asset Retirement Obligations

Our accrued obligations primarily relate to offshore platforms and pipelines, oil and gas properties, gas transmission pipelines and facilities, underground storage caverns, gas processing, fractionation, and compression facilities, and gas gathering well connections and pipelines. At the end of the useful life of each respective asset, we are legally obligated to dismantle offshore platforms and appropriately abandon offshore pipelines, to remove certain components of gas transmission facilities from the ground, to restore land and remove surface equipment at gas processing, fractionation, and compression facilities, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, to plug storage caverns and remove any related surface equipment, and to plug producing wells and remove any related surface equipment.

The following table presents the significant changes to our ARO, of which $1.827 billion and $1.590 billion are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued and other current liabilities at December 31, 2022 and 2021, respectively.

	Year Ended December 31,
	2022		2021
	(Millions)
Balance at beginning of year	$	1,665	$	1,222
Liabilities incurred (1)	77		336
Liabilities settled	(22)		(25)
Accretion	85		73
Revisions (2)	109		59
Balance at end of year	$	1,914	$	1,665

___________

(1)Includes $307 million of ARO in 2021 related to acquired upstream properties.

(2)Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2022 revisions reflect changes in removal cost estimates and increases in inflation rates, partially offset by increases in discount rates. The 2021 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, and increases in inflation rates.

The funds Transco collects through a portion of its rates to fund its ARO are deposited into an external trust account dedicated to funding its ARO (ARO Trust). (See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk.) Under its current rate settlement, Transco’s annual funding obligation is approximately $16 million, with installments to be deposited monthly.

XML

Intangible Assets

12 Months Ended

Dec. 31, 2022

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets [Text Block]

Note 10 – Intangible Assets

The gross carrying amount and accumulated amortization of intangible assets, included in Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet, at December 31 are as follows:

	2022				2021
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
	(Millions)
Customer relationships	$	10,065	$	(2,801)	$	9,593	$	(2,448)
Transportation and storage capacity contracts	267		(172)		267		(14)
Other intangible assets	6		(2)		6		(2)
	$	10,338	$	(2,975)	$	9,866	$	(2,464)

Customer Relationships

Customer relationships primarily relate to gas gathering, processing, and fractionation contractual customer relationships recognized in acquisitions. Contractual customer relationships are being amortized on a straight-line basis over a period of 30 years for most acquisitions, which represents a portion of the term over which the contractual customer relationships are expected to contribute to our cash flows.

We expense costs incurred to renew or extend the terms of our gas gathering, processing, and fractionation contracts with customers. Although a significant portion of the expected future cash flows associated with these contractual customer relationships are dependent on our ability to renew or extend the arrangements beyond the initial contract periods, these expected future cash flows are significantly influenced by the scope and pace of our producer customers’ drilling programs. Once producer customers’ wells are connected to our gathering infrastructure, their likelihood of switching to another provider before the wells are abandoned is reduced due to the significant capital investment required.

The amortization expense related to customer relationships was $353 million, $332 million, and $328 million in 2022, 2021, and 2020, respectively. The estimated amortization expense for each of the next five succeeding fiscal years is approximately $357 million.

Transportation and Storage Capacity Contracts

Certain transportation and storage capacity contracts were recognized as intangible assets as part of the Sequent Acquisition. (See Note 3 – Acquisitions.) The amortization expense related to transportation and storage capacity contracts was $158 million in 2022 and $14 million in 2021. The estimated amortization expense for each of the next five succeeding fiscal years is $51 million, $21 million, $10 million, $7 million, and $4 million.

XML

Accrued and Other Current Liabilities

12 Months Ended

Dec. 31, 2022

Accrued Liabilities, Current [Abstract]

Accrued and Other Current Liabilities [Text Block]

Note 11 – Accrued and Other Current Liabilities

	December 31,
	2022		2021
	(Millions)
Interest on debt	$	274	$	277
Employee costs	218		214
Regulatory liabilities (Note 1)	201		56
Contract liabilities	141		134
Asset retirement obligations (Note 9)	87		75
Operating lease liabilities (Note 13)	25		23
Other, including accrued loss contingencies	324		256
	$	1,270	$	1,035

XML

Debt and Banking Arrangements

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

Debt and Banking Arrangements [Text Block]

Note 12 – Debt and Banking Arrangements

Long-Term Debt

	December 31,
	2022		2021
	(Millions)
Transco:
7.08% Debentures due 2026	$	8	$	8
7.25% Debentures due 2026	200		200
7.85% Notes due 2026	1,000		1,000
4% Notes due 2028	400		400
3.25% Notes due 2030	700		700
5.4% Notes due 2041	375		375
4.45% Notes due 2042	400		400
4.6% Notes due 2048	600		600
3.95% Notes due 2050	500		500
Other financing obligation — Atlantic Sunrise	809		830
Other financing obligation — Leidy South	77		72
Other financing obligation — Dalton	252		254
Northwest Pipeline:
7.125% Debentures due 2025	85		85
4% Notes due 2027	500		500
Williams:
3.35% Notes due 2022	—		750
3.6% Notes due 2022	—		1,250
3.7% Notes due 2023	—		850
4.5% Notes due 2023	600		600
4.3% Notes due 2024	1,000		1,000
4.55% Notes due 2024	1,250		1,250
3.9% Notes due 2025	750		750
4% Notes due 2025	750		750
3.75% Notes due 2027	1,450		1,450
3.5% Notes due 2030	1,000		1,000
2.6% Notes due 2031	1,500		1,500
7.5% Debentures due 2031	339		339
7.75% Notes due 2031	252		252
8.75% Notes due 2032	445		445
4.65% Notes due 2032	1,000		—
6.3% Notes due 2040	1,250		1,250
5.8% Notes due 2043	400		400
5.4% Notes due 2044	500		500
5.75% Notes due 2044	650		650
4.9% Notes due 2045	500		500
5.1% Notes due 2045	1,000		1,000
4.85% Notes due 2048	800		800
3.5% Notes due 2051	650		650
5.3% Notes due 2052	750		—
Various — 7.7% to 8.72% Notes due 2022 to 2027	2		2
Unamortized debt issuance costs	(135)		(131)
Net unamortized debt premium (discount)	(55)		(56)
Total long-term debt, including current portion	22,554		23,675
Long-term debt due within one year	(627)		(2,025)
Long-term debt	$	21,927	$	21,650

Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, and incur additional debt. Default of these agreements could also restrict our ability to make certain distributions or repurchase equity.

The following table presents aggregate minimum maturities of long-term debt and other financing obligations, excluding net unamortized debt premium (discount) and debt issuance costs, for each of the next five years: 

	December 31, 2022
	(Millions)
2023	$	629
2024	2,281
2025	1,619
2026	1,245
2027	1,993

Issuances and retirements

On October 17, 2022, we early retired $850 million of 3.7 percent senior unsecured notes due January 15, 2023.

On August 8, 2022, we issued $1.0 billion of 4.65 percent senior unsecured notes due August 15, 2032, and $750 million of 5.30 percent senior unsecured notes due August 15, 2052.

On May 16, 2022, we early retired $750 million of 3.35 percent senior unsecured notes due August 15, 2022.

On January 18, 2022, we early retired $1.25 billion of 3.6 percent senior unsecured notes due March 15, 2022.

On October 8, 2021, we completed a public offering of $600 million of 2.6 percent senior unsecured notes due 2031. The new 2031 notes are an additional issuance of the $900 million of 2.6 percent senior unsecured notes due 2031 issued on March 2, 2021, and will trade interchangeably with such notes. Also, on October 8, 2021, we completed a public offering of $650 million of 3.5 percent senior unsecured notes due 2051.

We retired $371 million of 7.875 percent senior unsecured notes that matured on September 1, 2021.

On August 16, 2021, we early retired $500 million of 4.0 percent senior unsecured notes due November 15, 2021.

On August 17, 2020, we early retired $600 million of 4.125 percent senior unsecured notes due November 15, 2020.

On May 14, 2020, we completed a public offering of $1 billion of 3.5 percent senior unsecured notes due 2030.

On May 8, 2020, Transco issued $700 million of 3.25 percent senior unsecured notes due 2030 and $500 million of 3.95 percent senior unsecured notes due 2050 to investors in a private debt placement. In the fourth quarter of 2020, Transco filed a registration statement and completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act of 1933, as amended.

We retired $1.5 billion of 5.25 percent senior unsecured notes that matured on March 15, 2020.

We retired $14 million of 8.75 percent senior unsecured notes that matured on January 15, 2020.

Other financing obligations

During the construction of the Atlantic Sunrise, Leidy South, and Dalton projects, Transco received funding from co-owners for their proportionate share of construction costs. Amounts received were recorded within

noncurrent liabilities and the costs associated with construction were capitalized in the Consolidated Balance Sheet. Upon placing these projects into service Transco began utilizing the co-owners’ undivided interest in the assets, including the associated pipeline capacity, and reclassified the funding previously received from its co-owners from noncurrent liabilities to debt. The obligations, which mature in 2038, 2041, and 2052, respectively, require monthly interest and principal payments and bear interest rates of approximately 9 percent, 13 percent, and 9 percent, respectively.

Credit Facility

	December 31, 2022
	Stated Capacity		Outstanding
	(Millions)
Long-term credit facility (1)	$	3,750	$	—
Letters of credit under certain bilateral bank agreements			30

________________

(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.

Revolving credit facility

In October 2021, we along with Transco and Northwest Pipeline, the lenders named therein, and an administrative agent entered into an amended and restated credit agreement (Credit Agreement) that reduced aggregate commitments available from $4.5 billion to $3.75 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. The Credit Agreement was effective on October 8, 2021. The maturity date of the credit facility is October 8, 2026. However, the co-borrowers may request up to two extensions of the maturity date each for an additional one-year period to allow a maturity date as late as October 8, 2028, under certain circumstances. The Credit Agreement allows for swing line loans up to an aggregate of $200 million, subject to available capacity under the credit facility, and letters of credit commitments of $500 million. Transco and Northwest Pipeline are each able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers.

The Credit Agreement contains the following terms and conditions:

•Various covenants may limit, among other things, a borrower’s and its material subsidiaries’ ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets in certain circumstances, make certain distributions during an event of default, and each borrower and each borrower’s respective material subsidiaries’ ability to enter into certain restrictive agreements.

•If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for the respective borrowers and accelerate the maturity of the loans of the defaulting borrower under the credit facility and exercise other rights and remedies.

•Other than swing line loans, each time funds are borrowed, the applicable borrower may choose from two methods of calculating interest: a fluctuating base rate equal to an alternative base rate as defined in the Credit Agreement plus an applicable margin or a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus an applicable margin. We are required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin is determined by reference to a pricing schedule based on the applicable borrower’s senior unsecured long-term debt ratings and the commitment fee is determined by reference to a pricing schedule based on Williams’ senior unsecured long-term debt ratings. The Credit Agreement also includes customary provisions to provide for replacement of LIBOR with an alternative benchmark rate when LIBOR ceases to be available.

Significant financial covenants under the Credit Agreement require the ratio of debt to EBITDA (earnings before interest, taxes, depreciation, and amortization), each as defined in the Credit Agreement, to be no greater than 5.0 to 1.0, except that for any fiscal quarter in which the funding of the purchase price for an acquisition (whether effectuated as one or a series of related transactions) with an aggregate purchase price of $25 million or more has been effected, and the following two fiscal quarters (in each case subject to certain limitations), the ratio of debt to EBITDA is to be no greater than 5.5 to 1.

The ratio of debt to capitalization (defined as net worth plus debt), each as defined in the Credit Agreement, must be no greater than 65 percent for each of Transco and Northwest Pipeline.

At December 31, 2022, we are in compliance with these covenants.

Commercial Paper Program

In 2018, we entered into a $4 billion commercial paper program that has been reduced to $3.5 billion in connection with the October 2021 Credit Agreement. The maturities of the commercial paper notes vary but may not exceed 397 days from the date of issuance. The commercial paper notes are sold under customary terms in the commercial paper market and are issued at a discount from par, or, alternatively, are sold at par and bear varying interest rates on a fixed or floating basis. The net proceeds of issuances of the commercial paper notes are expected to be used to fund planned capital expenditures and for other general corporate purposes. At December 31, 2022, $350 million of commercial paper was outstanding at a weighted-average interest rate of 4.8 percent. We had no commercial paper outstanding at December 31, 2021.

Cash Payments for Interest (Net of Amounts Capitalized)

Cash payments for interest (net of amounts capitalized) were $1.117 billion in 2022, $1.137 billion in 2021, and $1.149 billion in 2020.

XML

Leases

12 Months Ended

Dec. 31, 2022

Leases [Abstract]

Leases [Text Block]

Note 13 – Leases

We are a lessee through noncancellable lease agreements for property and equipment consisting primarily of buildings, land, vehicles, and equipment used in both our operations and administrative functions.

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Lease Cost:
Operating lease cost	$	34	$	35	$	37
Variable lease cost	26		15		19
Sublease income	—		(1)		(1)
Total lease cost	$	60	$	49	$	55
Cash paid for operating lease liabilities	$	33	$	35	$	30

	December 31,
	2022		2021
	(Millions)
Other Information:
Right-of-use asset (included in Regulatory assets, deferred charges, and other)	$	162	$	159
Operating lease liabilities:
Current (included in Accrued and other current liabilities)	$	25	$	23
Noncurrent (included in Regulatory liabilities, deferred income, and other)	$	148	$	141
Weighted-average remaining lease term – operating leases (years)	13		13
Weighted-average discount rate – operating leases	4.62%		4.56%

At December 31, 2022, the following table represents our operating lease maturities, including renewal provisions that we have assessed as being reasonably certain of exercise, for each of the years ended December 31:

	(Millions)
2023	$	31
2024	26
2025	20
2026	20
2027	19
Thereafter	122
Total future lease payments	238
Less: Amount representing interest	65
Total obligations under operating leases	$	173

We are the lessor to certain lease agreements for office space in our headquarters building, which are insignificant to our financial statements.

XML

Equity-Based Compensation

12 Months Ended

Dec. 31, 2022

Share-Based Payment Arrangement, Noncash Expense [Abstract]

Equity-Based Compensation [Text Block]

Note 14 – Equity-Based Compensation

Williams’ Plan Information

The Williams Companies, Inc. 2007 Incentive Plan (the Plan) provides common-stock-based awards to both employees and nonmanagement directors. To date, 50 million new shares have been authorized for making awards under the Plan, including 10 million shares added on April 28, 2020. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. At December 31, 2022, 25 million

shares of our common stock were reserved for issuance pursuant to existing and future stock awards, of which 15 million shares were available for future grants.

Additionally, up to 5.2 million new shares of our common stock have been authorized to date to be available for sale under our Employee Stock Purchase Plan (ESPP), including 1.6 million shares added on April 28, 2020. Employees purchased 242 thousand shares at a weighted-average price of $24.57 per share during 2022. Approximately 1.2 million shares were available for purchase under the ESPP at December 31, 2022.

We recognize compensation expense on employee stock-based awards on a straight-line basis; forfeitures are recognized when they occur. Operating and maintenance expenses and Selling, general, and administrative expenses in our Consolidated Statement of Income include equity-based compensation expense in 2022, 2021, and 2020 of $73 million, $81 million, and $52 million, respectively. Income tax benefit recognized related to the stock-based compensation expense in 2022, 2021, and 2020 was $18 million, $20 million, and $13 million, respectively. Measured but unrecognized stock-based compensation expense at December 31, 2022, was $63 million, all of which related to restricted stock units. These amounts are expected to be recognized over a weighted-average period of 1.7 years.

Nonvested Restricted Stock Units

At December 31, 2022 and 2021, we had restricted stock units outstanding, including performance-based shares, of 6.9 million shares and 7.3 million shares, respectively, with a weighted-average fair value of $23.63 and $22.35, respectively. Restricted stock units generally vest after three years. Performance-based grants may vest at a range from zero percent to 200 percent of the original shares granted based on performance against a target. At December 31, 2022, there were 2.6 million performance-based shares outstanding.

Stock Options

There were no stock options granted in 2022, 2021, or 2020. At December 31, 2022, we had 2.8 million stock options that were both outstanding and exercisable, with a weighted-average exercise price of $34.32. The weighted-average remaining contractual life for stock options that were both outstanding and exercisable at December 31, 2022, was 2.8 years. Cash received for the exercise of stock options in 2022 was $49 million, and the related income tax benefit recognized in 2022 was $2 million.

XML

Fair Value Measurements, Guarantees, and Concentration of Credit Risk

12 Months Ended

Dec. 31, 2022

Fair Value Disclosures [Abstract]

Fair Value Measurements, Guarantees, and Concentration of Credit Risk [Text Block]

Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk

The following table presents, by level within the fair value hierarchy, certain of our significant financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, accounts payable, and commercial paper approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.

					Fair Value Measurements Using
	Carrying Amount		Fair Value		Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at December 31, 2022:
Measured on a recurring basis:
ARO Trust investments	$	230	$	230	$	230	$	—	$	—
Commodity derivative assets (1)	166		166		20		132		14
Commodity derivative liabilities (1)	(810)		(810)		(22)		(718)		(70)
Other financial assets (liabilities) - net	(5)		(5)		—		(5)		—
Additional disclosures:
Long-term debt, including current portion	(22,554)		(21,569)		—		(21,569)		—
Guarantees	(38)		(25)		—		(9)		(16)
Assets (liabilities) at December 31, 2021:
Measured on a recurring basis:
ARO Trust investments	$	260	$	260	$	260	$	—	$	—
Commodity derivative assets (2)	84		84		2		81		1
Commodity derivative liabilities (2)	(488)		(488)		(69)		(403)		(16)
Other financial assets (liabilities) - net	(7)		(7)		—		(7)		—
Additional disclosures:
Long-term debt, including current portion	(23,675)		(27,768)		—		(27,768)		—
Guarantees	(39)		(26)		—		(10)		(16)

(1)Net commodity derivative assets and liabilities exclude $202 million of net cash collateral in Level 1.

(2)Net commodity derivative assets and liabilities exclude $296 million of net cash collateral in Level 1.

Fair Value Methods

We use the following methods and assumptions in estimating the fair value of our financial instruments:

Assets measured at fair value on a recurring basis

ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust that is specifically designated to fund future ARO’s. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market and is reported in Regulatory assets, deferred charges, and other in our Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.

Commodity derivatives: Commodity derivatives include exchange-traded contracts and OTC contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis. We also have other derivatives related to asset management agreements and other contracts that require physical delivery. Derivatives classified as Level 1 are valued using New York Mercantile Exchange (NYMEX) futures prices. Derivatives classified as Level 2 are valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers. Derivatives classified as Level 3 are valued using a combination of observable and unobservable inputs. The fair value amounts are presented on a net basis and reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements and cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Commodity derivative assets are reported in Derivative assets and Regulatory assets, deferred charges, and other in our Consolidated Balance Sheet. Commodity derivative liabilities are reported in Derivative liabilities and Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet. Changes in the fair value of our derivative assets and liabilities are recorded in Net gain (loss) on commodity derivatives and Net processing commodity expenses in our Consolidated Statement of Income. See Note 16 – Derivatives for additional information on our derivatives.

The following table presents a reconciliation of changes in fair value of our net commodity derivatives classified as Level 3 in the fair value hierarchy.

	Year Ended December 31,
	2022		2021
	(Millions)
Balance at beginning of period	$	(15)	$	(2)
Gains (losses) included in our Consolidated Statement of Income	(31)		(62)
Purchases, issuances, and settlements	(5)		13
Acquired derivatives (Note 3)	—		24
Transfers into Level 3	(24)		—
Transfers out of Level 3	19		12
Balance at end of period	$	(56)	$	(15)

A substantial portion of the carrying value of our Level 3 derivatives at December 31, 2022, relates to a long-term physical natural gas purchase contract associated with an ongoing pipeline expansion project. The valuation of this contract reflects the extrapolation of forward natural gas prices for periods beyond observable price curves, which is considered a significant unobservable input.

Additional fair value disclosures

Long-term debt, including current portion: The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair values of the financing obligations associated with our Dalton, Leidy South, and Atlantic Sunrise projects, which are included within long-term debt, were determined using an income approach (see Note 12 – Debt and Banking Arrangements).

Guarantees: Guarantees primarily consist of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation that extends through 2042. Guarantees also include an indemnification related to a disposed operation.

To estimate the fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying

value of the WilTel guarantee is reported in Accrued and other current liabilities in our Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $24 million at December 31, 2022. Our exposure declines systematically through the remaining term of WilTel’s obligation.

The fair value of the guarantee associated with the indemnification related to a disposed operation was estimated using an income approach that considered probability-weighted scenarios of potential levels of future performance. The terms of the indemnification do not limit the maximum potential future payments associated with the guarantee. The carrying value of this guarantee is reported in Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet.

We are required by our revolving credit agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have no carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.

Nonrecurring fair value measurements

During the first quarter of 2020, we observed a significant decline in the publicly traded price of our common stock on the New York Stock Exchange, which declined 40 percent during the quarter, including a 26 percent decline in the month of March. These changes were generally attributed to macroeconomic and geopolitical conditions, including significant declines in crude oil prices driven by both surplus supply and a decrease in demand caused by the coronavirus pandemic. As a result of these conditions, we performed an interim assessment of the goodwill associated with our Northeast G&P reporting unit as of March 31, 2020.

The assessment considered the total fair value of the businesses within the Northeast G&P reporting unit, which was determined using income and market approaches. We utilized internally developed industry weighted-average discount rates and estimates of valuation multiples of comparable publicly traded gathering and processing companies. In assessing the fair value as of the March 31, 2020, measurement date, we were required to consider recent publicly available indications of value, which included lower observed publicly traded EBITDA market multiples as compared with recent history and significantly higher industry weighted-average discount rates. The fair value of the reporting unit was further reconciled to our estimated total enterprise value as of March 31, 2020, which considered observable valuation multiples of comparable publicly traded companies applied to each distinct business including the Northeast G&P reporting unit. This assessment indicated that the estimated fair value of the Northeast G&P reporting unit was below its carrying value, including goodwill. As a result of this Level 3 measurement, we recognized a full impairment charge of $187 million as of March 31, 2020, in Impairment of goodwill in our Consolidated Statement of Income. Our partner’s $65 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in our Consolidated Statement of Income.

The following table presents impairments of assets and equity-method investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy, except as specifically noted.

					Impairments
					Year Ended December 31,
	Segment	Date of Measurement	Fair Value		2022		2021		2020
			(Millions)
Impairment of certain assets:
Certain capitalized project costs (1)	Transmission & Gulf of Mexico	June 30, 2021	$	1			$	2
Certain capitalized project costs (1)	Transmission & Gulf of Mexico	December 31, 2020	42						$	170
Certain gathering assets (2)	Northeast G&P	December 31, 2020	5						12
Impairment of certain assets					$	—	$	2	$	182
Impairment of equity-method investments:
RMM (3)	West	December 31, 2020	$	421					$	108
RMM (4)	West	March 31, 2020	557						243
Brazos Permian II (4)	West	March 31, 2020	—						193
BRMH (5)	Northeast G&P	March 31, 2020	191						229
Appalachia Midstream Investments (5)	Northeast G&P	March 31, 2020	2,700						127
Aux Sable (5)	Northeast G&P	March 31, 2020	7						39
Laurel Mountain (5)	Northeast G&P	March 31, 2020	236						10
Discovery (5)	Transmission & Gulf of Mexico	March 31, 2020	367						97
Impairment of equity-method investments					$	—	$	—	$	1,046

______________

(1)Relates to capitalized project development costs for the Northeast Supply Enhancement project. Approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection have been denied and we have not refiled at this time. Beginning in May 2020, we discontinued capitalization of costs related to this project. Considering that the customer precedent agreements and FERC certificate for the project remain in effect, we had previously concluded that the probability of completing the project was sufficient to not require impairment. However, developments in the political and regulatory environments caused us to slightly lower that assessed probability such that the capitalized project costs required impairment. The estimated fair value of the materials within the capitalized project costs at December 31, 2020 considered other internal uses and salvage values for the Property, plant, and equipment – net. The remaining capitalized costs were determined to have no fair value. The estimated fair value of certain capitalized project costs at June 30, 2021, was determined by a market approach, which incorporated an indication of interest by a third-party.

(2)Relates to a gathering system in the Marcellus Shale region, that was sold in 2021. The estimated fair value of the Property, plant, and equipment – net and Intangible assets – net of accumulated amortization was determined using a market approach, which incorporated an indication of interest by a third party. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy.

(3)During the fourth quarter of 2020, RMM renegotiated service contracts with a significant customer in connection with the customer’s Chapter 11 bankruptcy proceedings. The renegotiated contracts result in lower service rates and lower projected future cash flows. As a result, we evaluated this investment for other-than-temporary impairment. The fair value was measured using an income approach. We utilized a discount rate of 18 percent in our analysis.

(4)Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The fair value was measured using an income approach. Both investees operate in primarily oil-driven basins where significant expected reductions in producer activities led to reduced estimates of expected future cash flows. Our fair value estimates also reflected discount rates of approximately 17 percent for these investments. We also considered any debt held at the investee level, and its impact to fair value. The industry weighted-average discount rates utilized were significantly influenced by the market declines previously discussed.

(5)Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The impairments within our Northeast G&P segment are primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices which historically trend with crude oil prices. The fair values of our investments in BRMH and Aux Sable Liquid Products LP (Aux Sable) were estimated using a market approach, reflecting valuation multiples ranging from 5.0x to 6.2x EBITDA (weighted-average 6.0x). The fair values of the other investments, including gathering systems that are part of Appalachia Midstream Investments, were estimated using an income approach, with discount rates ranging from 9.7 percent to 13.5 percent (weighted-average 12.6 percent). We also considered any debt held at the investee level, and its impact to fair value. The assumed valuation multiples and industry weighted-average discount rates utilized were both significantly influenced by the market declines previously discussed.

Concentration of Credit Risk

Accounts receivable

The following table summarizes concentration of receivables, net of allowances:

	December 31,
	2022		2021
	(Millions)
NGLs, natural gas, and related products and services	$	505	$	486
Regulated interstate natural gas transportation and storage	311		274
Marketing of natural gas and NGLs	858		609
Upstream activities	97		82
Accounts Receivable related to revenues from contracts with customers	1,771		1,451
Receivables from derivatives	889		462
Other accounts receivable	63		65
Trade accounts and other receivables - net	$	2,723	$	1,978

Customers include producers, distribution companies, industrial users, gas marketers, and pipelines primarily located in the continental United States. As a general policy, collateral is not required for receivables with the exception of the marketing receivables discussed below. Customers’ financial condition and credit worthiness are evaluated regularly and, based upon this evaluation, we may obtain collateral to support receivables.

We use established credit policies to determine and monitor the creditworthiness of gas marketing and trading counterparties, including requirements to post collateral or other credit security, as well as the quality of pledged collateral. Collateral or credit security is most often in the form of cash or letters of credit from an investment-grade

financial institution, but may also include U.S. government securities. We also utilize netting agreements whenever possible to mitigate exposure to gas marketing and trading counterparty credit risk. When more than one derivative transaction with the same counterparty is outstanding and a legally enforceable netting agreement exists with that counterparty, the “net” mark-to-market exposure represents a reasonable measure of our credit risk with that counterparty.

XML

Derivatives

12 Months Ended

Dec. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives [Text Block]

Note 16 – Derivatives

Commodity-Related Derivatives

We are exposed to commodity price risk. To manage this volatility, we use various contracts in our marketing and trading activities that generally meet the definition of derivatives. Derivative positions are monitored using techniques including, but not limited to, value at risk. Derivative instruments are recognized at fair value in our Consolidated Balance Sheet as either assets or liabilities and are presented on a net basis by counterparty, net of margin deposits. See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk for additional fair value information. In our Consolidated Statement of Cash Flows, any cash impacts of settled commodity-related derivatives are recorded as operating activities.

We enter into commodity-related derivatives to economically hedge exposures to natural gas, NGLs, and crude oil and retain exposure to price changes that can, in a volatile energy market, be material and can adversely affect our results of operations.

At December 31, 2022, the notional volume of the net long (short) positions for our commodity-related derivative contracts were as follows:

	Commodity	Unit of Measure	Net Long (Short) Position
Index Risk	Natural Gas	MMBtu	745,415,032
Central Hub Risk - Henry Hub	Natural Gas	MMBtu	(46,154,200)
Basis Risk	Natural Gas	MMBtu	(50,737,802)
Central Hub Risk - Mont Belvieu	Natural Gas Liquids	Barrels	35,548
Basis Risk	Natural Gas Liquids	Barrels	(3,880,364)
Central Hub Risk - WTI	Crude Oil	Barrels	(123,250)

Derivative Financial Statement Presentation

The fair value of commodity-related derivatives, which are not designated as hedging instruments for accounting purposes, was reflected as follows:

	December 31, 2022				December 31, 2021
Derivative Category	Assets		(Liabilities)		Assets		(Liabilities)
	(Millions)
Current	$	1,099	$	(1,278)	$	619	$	(760)
Noncurrent	269		(734)		166		(429)
Total derivatives	$	1,368	$	(2,012)	$	785	$	(1,189)
Counterparty and collateral netting offset	(1,034)		1,236		(476)		772
Amounts recognized in our Consolidated Balance Sheet	$	334	$	(776)	$	309	$	(417)

The pre-tax effects of commodity-related derivative instruments in Net gain (loss) on commodity derivatives reflected within Total revenues and Net processing commodity expenses in our Consolidated Statement of Income were as follows:

	Gain (Loss)
	Year Ended December 31,
	2022		2021		2020
	(Millions)
Realized commodity-related derivatives designated as hedging instruments	$	—	$	(55)	$	(2)
Realized commodity-related derivatives not designated as hedging instruments	(91)		16		(3)
Unrealized commodity-related derivatives not designated as hedging instruments	(296)		(109)		—
Net gain (loss) on commodity derivatives	$	(387)	$	(148)	$	(5)
Realized commodity-related derivatives not designated as hedging instruments in Net processing commodity expenses	$	16	$	2	$	1
Unrealized commodity-related derivatives not designated as hedging instruments in Net processing commodity expenses	$	47	$	—	$	—

Contingent Features

Generally, collateral may be provided by a parent guaranty, letter of credit, or cash. If collateral is required, fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are offset against fair value amounts recognized for derivatives executed with the same counterparty.

We have specific trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, we would need to post collateral to continue transacting business with these counterparties. At December 31, 2022, the contractually required collateral in the event of a credit rating downgrade to non-investment grade status was $13 million.

We maintain accounts with brokers or the clearing houses of certain exchanges to facilitate financial derivative transactions. Based on the value of the positions in these accounts and the associated margin requirements, we may be required to deposit cash into these accounts. At December 31, 2022, and 2021, net cash collateral held on deposit in broker margin accounts was $202 million and $296 million, respectively.

XML

Contingent Liabilities and Commitments

12 Months Ended

Dec. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Contingent Liabilities and Commitments [Text Block]

Note 17 – Contingent Liabilities and Commitments

Alaska Refinery Contamination Litigation

We are involved in litigation arising from our ownership and operation of the North Pole Refinery in North Pole, Alaska, from 1980 until 2004, through our wholly owned subsidiaries Williams Alaska Petroleum Inc. (WAPI) and MAPCO Inc. We sold the refinery to Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., in 2004. The litigation involves three cases, with filing dates ranging from 2010 to 2014. The actions primarily arise from sulfolane contamination allegedly emanating from the refinery. A putative class action lawsuit was filed by James West in 2010 naming us, WAPI, and FHRA as defendants. We and FHRA filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA settled the claim with James West. Certain claims by FHRA against us were resolved by the Alaska Supreme Court in our favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane were remanded to the Alaska Superior

Court. The State of Alaska filed its action in March 2014, seeking damages. The City of North Pole (North Pole) filed its lawsuit in November 2014, seeking past and future damages, as well as punitive damages. Both we and WAPI asserted counterclaims against the State of Alaska and North Pole, and cross-claims against FHRA. FHRA has also filed cross-claims against us.

The underlying factual basis and claims in the cases are similar and may duplicate exposure. As such, in February 2017, the three cases were consolidated into one action in state court containing the remaining claims from the James West case and those of the State of Alaska and North Pole. The State of Alaska later announced the discovery of additional contaminants per- and polyfluoralkyl (PFOS and PFOA) offsite of the refinery, and the court permitted the State of Alaska to amend its complaint to add a claim for offsite PFOS/PFOA contamination. The court subsequently remanded the offsite PFOS/PFOA claims to the Alaska Department of Environmental Conservation for investigation and stayed the claims pending their potential resolution at the administrative agency. Several trial dates encompassing all three cases have been scheduled and stricken. In the summer of 2019, the court deconsolidated the cases for purposes of trial. A bench trial on all claims except North Pole’s claims began in October 2019.

In January 2020, the Alaska Superior Court issued its Memorandum of Decision finding in favor of the State of Alaska and FHRA, with the total incurred and potential future damages estimated to be $86 million. The court found that FHRA is not entitled to contractual indemnification from us because FHRA contributed to the sulfolane contamination. On March 23, 2020, the court entered final judgment in the case. Filing deadlines were stayed until May 1, 2020. However, on April 21, 2020, we filed a Notice of Appeal. We also filed post-judgment motions including a Motion for New Trial and a Motion to Alter or Amend the Judgment. These post-trial motions were resolved with the court’s denial of the last motion on June 11, 2020. Our Statement of Points on Appeal was filed on July 13, 2020. On June 22, 2020, the court stayed the North Pole’s case pending resolution of the appeal in the State of Alaska and FHRA case. On December 23, 2020, we filed our opening brief on appeal. Oral argument was held on December 15, 2021. We have recorded an accrued liability in the amount of our estimate of the probable loss. It is reasonably possible that we may not be successful on appeal and could ultimately pay up to the amount of judgment.

Royalty Matters

Certain of our customers, including Chesapeake Energy Corporation (Chesapeake), have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases filed in Pennsylvania based on allegations that we improperly participated with Chesapeake in causing the alleged royalty underpayments. We believe that the claims asserted are subject to indemnity obligations owed to us by Chesapeake. Chesapeake has reached a settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement applies to both Chesapeake and us. The settlement does not require any contribution from us. On August 23, 2021, the court approved the settlement, but two objectors filed an appeal with the United States Court of Appeals for the Fifth Circuit.

Litigation Against Energy Transfer and Related Parties

On April 6, 2016, we filed suit in Delaware Chancery Court against Energy Transfer Equity, L.P. (Energy Transfer) and LE GP, LLC (the general partner for Energy Transfer) alleging willful and material breaches of the Agreement and Plan of Merger (ETE Merger Agreement) with Energy Transfer resulting from the private offering by Energy Transfer on March 8, 2016, of Series A Convertible Preferred Units (Special Offering) to certain Energy Transfer insiders and other accredited investors. The suit seeks, among other things, an injunction ordering the defendants to unwind the Special Offering and to specifically perform their obligations under the ETE Merger Agreement. On April 19, 2016, we filed an amended complaint seeking the same relief. On May 3, 2016, Energy Transfer and LE GP, LLC filed an answer and counterclaims.

On May 13, 2016, we filed a separate complaint in Delaware Chancery Court against Energy Transfer, LE GP, LLC and the other Energy Transfer affiliates that are parties to the ETE Merger Agreement, alleging material

breaches of the ETE Merger Agreement for failing to cooperate and use necessary efforts to obtain a tax opinion required under the ETE Merger Agreement (Tax Opinion) and for otherwise failing to use necessary efforts to consummate the merger under the ETE Merger Agreement wherein we would be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger). The suit sought, among other things, a declaratory judgment and injunction preventing Energy Transfer from terminating or otherwise avoiding its obligations under the ETE Merger Agreement due to any failure to obtain the Tax Opinion.

The Court of Chancery coordinated the Special Offering and Tax Opinion suits. On May 20, 2016, the Energy Transfer defendants filed amended affirmative defenses and verified counterclaims in the Special Offering and Tax Opinion suits, alleging certain breaches of the ETE Merger Agreement by us and seeking, among other things, a declaration that we were not entitled to specific performance, that Energy Transfer could terminate the ETC Merger, and that Energy Transfer is entitled to a $1.48 billion termination fee. On June 24, 2016, following a two-day trial, the court issued a Memorandum Opinion and Order denying our requested relief in the Tax Opinion suit. The court did not rule on the substance of our claims related to the Special Offering or on the substance of Energy Transfer’s counterclaims. On June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017.

On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the ETE Merger Agreement by defendants. On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the ETE Merger Agreement. On December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument, which the Court of Chancery denied on April 16, 2018. Trial was held May 10 through May 17, 2021. On December 29, 2021, the court entered judgment in our favor in the amount of $410 million, plus interest at the contractual rate, and our reasonable attorneys’ fees and expenses. On September 21, 2022, the court entered a final order and judgment awarding us the termination fee, attorney’s fees, expenses, and interest in the amount of $602 million plus additional interest starting September 17, 2022. Energy Transfer has appealed to the Delaware Supreme Court.

Environmental Matters

We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of December 31, 2022, we have accrued liabilities totaling $40 million for these matters, as discussed below. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At December 31, 2022, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

The EPA and various state regulatory agencies routinely propose and promulgate new rules and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine maximum achievable control technology, reviews and updates to the National Ambient Air Quality Standards, and rules for new and existing source performance standards for volatile

organic compound and methane. We continuously monitor these regulatory changes and how they may impact our operations. Implementation of new or modified regulations may result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in our Consolidated Balance Sheet for both new and existing facilities in affected areas; however, due to regulatory uncertainty on final rule content and applicability timeframes, we are unable to reasonably estimate the cost of these regulatory impacts at this time.

Continuing operations

Our interstate gas pipelines are involved in remediation and monitoring activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At December 31, 2022, we have accrued liabilities of $13 million for these costs and expect to recover approximately $4 million through rates.

We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At December 31, 2022, we have accrued liabilities totaling $10 million for these costs.

Former operations

We have potential obligations in connection with assets and businesses we no longer operate. These potential obligations include remediation activities at the direction of federal and state environmental authorities and the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described below.

•Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations;

•Former petroleum products and natural gas pipelines;

•Former petroleum refining facilities;

•Former exploration and production and mining operations;

•Former electricity and natural gas marketing and trading operations.

At December 31, 2022, we have accrued environmental liabilities of $17 million related to these matters.

Other Divestiture Indemnifications

Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided.

At December 31, 2022, other than as previously disclosed, we are not aware of any material claims against us involving the above-described indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made.

In addition to the foregoing, various other proceedings are pending against us that are incidental to our operations, none of which are expected to be material to our expected future annual results of operations, liquidity, and financial position.

Summary

We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties.

Commitments

Commitments for construction and acquisition of property, plant, and equipment are approximately $439 million at December 31, 2022.

Commitments for Gas & NGL Marketing Services pipeline transportation capacity and storage capacity are approximately $546 million at December 31, 2022.

XML

Segment Disclosures

12 Months Ended

Dec. 31, 2022

Segment Reporting [Abstract]

Segment Disclosures [Text Block]

Note 18 – Segment Disclosures

Our reportable segments are Transmission & Gulf of Mexico, Northeast G&P, West, and Gas & NGL Marketing Services. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.)

Performance Measurement

We evaluate segment operating performance based upon Modified EBITDA. This measure represents the basis of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments. Intersegment Service revenues primarily represent transportation services provided to our marketing business and gathering services provided to our oil and gas properties. Intersegment Product sales primarily represent the sale of natural gas and NGLs from our natural gas processing plants and our oil and gas properties to our marketing business.

We define Modified EBITDA as follows:

•Net income (loss) before:

◦Provision (benefit) for income taxes;

◦Interest incurred, net of interest capitalized;

◦Equity earnings (losses);

◦Impairment of equity-method investments;

◦Other investing income (loss) – net;

◦Impairment of goodwill;

◦Depreciation and amortization expenses;

◦Accretion expense associated with asset retirement obligations for nonregulated operations.

•This measure is further adjusted to include our proportionate share (based on ownership interest) of Modified EBITDA from our equity-method investments calculated consistently with the definition described above.

The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in our Consolidated Statement of Income:

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Modified EBITDA by segment:
Transmission & Gulf of Mexico	$	2,674	$	2,621	$	2,379
Northeast G&P	1,796		1,712		1,489
West	1,211		961		947
Gas & NGL Marketing Services (1)	(40)		22		51
Other	434		178		(15)
	6,075		5,494		4,851
Accretion expense associated with asset retirement obligations for nonregulated operations	(51)		(45)		(35)
Depreciation and amortization expenses	(2,009)		(1,842)		(1,721)
Impairment of goodwill	—		—		(187)
Equity earnings (losses)	637		608		328
Impairment of equity-method investments	—		—		(1,046)
Other investing income (loss) – net	16		7		8
Proportional Modified EBITDA of equity-method investments	(979)		(970)		(749)
Interest expense	(1,147)		(1,179)		(1,172)
(Provision) benefit for income taxes	(425)		(511)		(79)
Net income (loss)	$	2,117	$	1,562	$	198

____________

(1)    Modified EBITDA for 2022, 2021, and 2020, includes charges of $161 million, $15 million, and $17 million respectively, associated with lower of cost or net realizable value adjustments to our inventory. These charges are reflected in Product Sales or Product costs in our Consolidated Statement of Income (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies). Net unrealized commodity-related derivatives gains of $47 million in 2022 and $0 in 2021 and 2020 are reflected in Net processing commodity expenses.

The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Income and Other financial information:

	Transmission & Gulf of Mexico		Northeast G&P		West		Gas & NGL Marketing Services (1)		Other		Eliminations		Total
	(Millions)
2022
Segment revenues:
Service revenues
External	$	3,461	$	1,613	$	1,443	$	3	$	16	$	—	$	6,536
Internal	118		41		99		—		8		(266)		—
Total service revenues	3,579		1,654		1,542		3		24		(266)		6,536
Total service revenues – commodity consideration	64		14		182		—		—		—		260
Product sales
External	228		28		145		4,052		103		—		4,556
Internal	176		106		696		(518)		603		(1,063)		—
Total product sales	404		134		841		3,534		706		(1,063)		4,556
Net gain (loss) on commodity derivatives
Realized	—		—		(4)		17		(104)		—		(91)
Unrealized	—		—		—		(321)		25		—		(296)
Total net gain (loss) on commodity derivatives (2)	—		—		(4)		(304)		(79)		—		(387)
Total revenues	$	4,047	$	1,802	$	2,561	$	3,233	$	651	$	(1,329)	$	10,965
Other financial information:
Additions to long-lived assets	$	1,420	$	261	$	1,507	$	4	$	406	$	—	$	3,598
Proportional Modified EBITDA of equity-method investments	193		654		132		—		—		—		979
2021
Segment revenues:
Service revenues
External	$	3,310	$	1,490	$	1,178	$	3	$	20	$	—	$	6,001
Internal	75		38		70		—		12		(195)		—
Total service revenues	3,385		1,528		1,248		3		32		(195)		6,001
Total service revenues – commodity consideration	52		7		179		—		—		—		238
Product sales
External	231		13		60		4,094		138		—		4,536
Internal	118		86		583		198		195		(1,180)		—
Total product sales	349		99		643		4,292		333		(1,180)		4,536
Net gain (loss) on commodity derivatives
Realized	—		—		(44)		25		(20)		—		(39)
Unrealized	—		—		—		(109)		—		—		(109)
Total net gain (loss) on commodity derivatives (2)	—		—		(44)		(84)		(20)		—		(148)
Total revenues	$	3,786	$	1,634	$	2,026	$	4,211	$	345	$	(1,375)	$	10,627
Other financial information:
Additions to long-lived assets	$	861	$	164	$	209	$	1	$	620	$	—	$	1,855
Proportional Modified EBITDA of equity-method investments	183		682		105		—		—		—		970

	Transmission & Gulf of Mexico		Northeast G&P		West		Gas & NGL Marketing Services (1)		Other		Eliminations		Total
	(Millions)
2020
Segment revenues:
Service revenues
External	$	3,207	$	1,416	$	1,248	$	32	$	21	$	—	$	5,924
Internal	50		49		24		—		13		(136)		—
Total service revenues	3,257		1,465		1,272		32		34		(136)		5,924
Total service revenues – commodity consideration	21		7		101		—		—		—		129
Product sales
External	144		16		20		1,491		—		—		1,671
Internal	47		41		132		111		—		(331)		—
Total product sales	191		57		152		1,602		—		(331)		1,671
Net gain (loss) on commodity derivatives
Realized	—		—		(2)		(3)		—		—		(5)
Unrealized	—		—		—		—		—		—		—
Total net gain (loss) on commodity derivatives (2)	—		—		(2)		(3)		—		—		(5)
Total revenues	$	3,469	$	1,529	$	1,523	$	1,631	$	34	$	(467)	$	7,719
Other financial information:
Additions to long-lived assets	$	706	$	137	$	318	$	—	$	122	$	—	$	1,283
Proportional Modified EBITDA of equity-method investments	166		473		110		—		—		—		749

______________

(1)    See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.

(2)    We record transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue.

Segment assets include Investments, Property, plant, and equipment – net, and Intangible assets – net of accumulated amortization. The following table reflects segment assets and equity-method investments by reportable segments:

	Segment Assets				Equity-Method Investments
	December 31, 2022		December 31, 2021		December 31, 2022		December 31, 2021
	(Millions)
Transmission & Gulf of Mexico	$	17,795	$	17,142	$	629	$	602
Northeast G&P	13,539		13,861		3,566		3,681
West	10,710		9,698		843		838
Gas & NGL Marketing Services	130		294		—		—
Other	1,143		792		10		—
Total	43,317		41,787		$	5,048	$	5,121
Total current assets	3,797		4,549
Regulatory assets, deferred charges, and other	1,319		1,276
Total assets	$	48,433	$	47,612

XML

Subsequent Events

12 Months Ended

Dec. 31, 2022

Subsequent Events [Abstract]

Subsequent Events [Text Block]

Note 19 – Subsequent Events

Quarterly Dividends to Common Stockholders

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

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 (MountainWest Acquisition), for $1.08 billion of cash funded with available sources of short-term liquidity 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. Due to the timing, the initial purchase price accounting for the transaction was not yet complete at the time of filing.

XML

Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2022

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

Schedule II - Valuation and Qualifying Accounts [Text Block]

The Williams Companies, Inc.

Schedule II — Valuation and Qualifying Accounts

			Additions
	Beginning Balance		Charged (Credited) To Costs and Expenses		Other		Deductions		Ending Balance
	(Millions)
2022
Deferred tax asset valuation allowance (1)	$	297	$	(97)	$	—	$	—	$	200
2021
Deferred tax asset valuation allowance (1)	325		(28)		—		—		297
2020
Deferred tax asset valuation allowance (1)	319		6		—		—		325

__________

(1)    Deducted from related assets.

XML

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

Principles of consolidation [Policy Text Block]

Principles of consolidation

The consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain ventures in which we own an undivided interest. Our judgment is required to evaluate whether we control an entity. Key areas of that evaluation include:

•Determining whether an entity is a VIE (see Note 2 – Variable Interest Entities);

•Determining whether we are the primary beneficiary of a VIE, including evaluating which activities of the VIE most significantly impact its economic performance and the degree of power that we and our related parties have over those activities through our variable interests;

•Identifying events that require reconsideration of whether an entity is a VIE and continuously evaluating whether we are a VIE’s primary beneficiary;

•Evaluating whether other owners in entities that are not VIEs are able to effectively participate in significant decisions that would be expected to be made in the ordinary course of business such that we do not have the power to control such entities.

We apply the equity method of accounting to investments over which we exercise significant influence but do not control. Distributions received from equity-method investees are presented in our Consolidated Statement of Cash Flows according to the nature of the distributions approach, which classifies distributions received from equity-method investees as either returns on investment (cash inflows from operating activities) or returns of

investment (cash inflows from investing activities) based on the nature of the activities of the equity-method investee that generated the distribution.

Use of estimates [Policy Text Block]

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Significant estimates and assumptions include:

•Impairment assessments of investments, property, plant, and equipment, and intangible assets;

•Litigation-related contingencies;

•Environmental remediation obligations;

•Depreciation and/or amortization of long-lived assets, which are comprised of property, plant, and equipment, and intangible assets;

•Depreciation and/or amortization of equity-method investment basis differences;

•Asset retirement obligations (AROs);

•Measurement of fair value of derivatives;

•Pension and postretirement valuation variables;

•Measurement of regulatory liabilities;

•Measurement of deferred income tax assets and liabilities, including assumptions related to the realization of deferred income tax assets;

•Revenue recognition, including estimates utilized in recognition of deferred revenue;

•Purchase price accounting.

These estimates are discussed further throughout these notes.

Regulatory accounting [Policy Text Block]

Regulatory accounting

Transco and Northwest Pipeline are regulated by the Federal Energy Regulatory Commission (FERC), and their rates are established by the FERC. Therefore, we have determined that it is appropriate under Accounting Standards Codification (ASC) Topic 980, “Regulated Operations,” (ASC 980) that certain costs that would otherwise be charged to expense should be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense should be deferred as regulatory liabilities, based on the expected return to customers in future rates. Management’s expected recovery of deferred costs and return of deferred credits generally results from specific decisions by regulators granting such ratemaking treatment. We record certain incurred costs and obligations as regulatory assets or liabilities if, based on regulatory orders or other available evidence, it is probable that the costs or obligations will be included in amounts allowable for recovery or refunded in future rates. Accounting for these operations that are regulated can differ from the accounting requirements for nonregulated operations. For example, for regulated operations, allowance for funds used during construction (AFUDC) represents the estimated cost of debt and equity funds applicable to utility plant in the process of construction and is capitalized as a cost of property, plant, and equipment because it constitutes an actual cost of construction under established regulatory practices; nonregulated operations are only allowed to capitalize the cost of debt funds related to construction activities, while a component for equity is prohibited. The

components of our regulatory assets and liabilities relate to the effects of deferred taxes on equity funds used during construction, AROs, shipper imbalance activity, fuel and power cost differentials, depreciation, negative salvage, pension and other postretirement benefits, customer tax refunds, and rate allowances for deferred income taxes at a historically higher federal income tax rate.

Our current and noncurrent regulatory asset and liability balances at December 31, 2022 and 2021 are as follows:

	December 31,
	2022		2021
	(Millions)
Current assets reported within Other current assets and deferred charges	$	138	$	111
Noncurrent assets reported within Regulatory assets, deferred charges, and other	459		415
Total regulated assets	$	597	$	526
Current liabilities reported within Accrued and other current liabilities	$	201	$	56
Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other	1,233		1,324
Total regulated liabilities	$	1,434	$	1,380

Revenue recognition [Policy Text Block]

Revenue recognition

Customers in our gas pipeline businesses are comprised of public utilities, municipalities, gas marketers and producers, intrastate pipelines, direct industrial users, and electrical power generators. Customers in our midstream businesses are comprised of oil and natural gas producer counterparties. Customers for our product sales are comprised of public utilities, gas marketers, and direct industrial users.

Service revenue contracts from our gas pipeline and midstream businesses contain a series of distinct services, with the majority of our contracts having a single performance obligation that is satisfied over time as the customer simultaneously receives and consumes the benefits provided by our performance. Most of our product sales contracts have a single performance obligation with revenue recognized at a point in time when the products have been sold and delivered to the customer.

Certain customers reimburse us for costs we incur associated with construction of property, plant, and equipment utilized in our operations. For our rate-regulated gas pipeline businesses that apply ASC 980, we follow FERC guidelines with respect to reimbursement of construction costs. FERC tariffs only allow for cost reimbursement and are non-negotiable in nature; thus, in our judgment, the construction activities do not represent an ongoing major and central operation of our gas pipeline businesses and are not within the scope of ASC Topic 606, “Revenue from Contracts with Customers”. Accordingly, cost reimbursements are treated as a reduction to the cost of the constructed asset, which are referred to as Contributions in aid of construction in our Consolidated Statement of Cash Flows. For our midstream businesses, reimbursement and service contracts with customers are viewed together as providing the same commercial objective, as we have the ability to negotiate the mix of consideration between reimbursements and amounts billed over time. Accordingly, we generally recognize reimbursements of construction costs from customers on a gross basis as a contract liability separate from the associated costs included within property, plant, and equipment. The contract liability is recognized into service revenues as the underlying performance obligations are satisfied.

Service Revenues

Gas pipeline businesses: Revenues from our regulated interstate natural gas pipeline businesses, which are subject to regulation by certain state and federal authorities, including the FERC, include both firm and interruptible transportation and storage contracts. Firm transportation and storage agreements provide for a daily or monthly reservation charge based on the pipeline or storage capacity reserved, and a commodity charge

based on the volume of natural gas delivered/stored, each at rates specified in our FERC tariffs or based on negotiated contractual rates, with contract terms that are generally long-term in nature. Most of our long-term contracts contain an evergreen provision, which allows the contracts to be extended for periods primarily up to one year in length an indefinite number of times following the specified contract term and until terminated generally by either us or the customer. Interruptible transportation and storage agreements provide for a volumetric charge based on actual commodity transportation or storage utilized in the period in which those services are provided, and the contracts are generally limited to one-month periods or less. Our performance obligations related to our interstate natural gas pipeline businesses include the following:

•Firm transportation or storage under firm transportation and storage contracts—an integrated package of services typically constituting a single performance obligation, which includes standing ready to provide such services and receiving, transporting or storing (as applicable), and redelivering commodities;

•Interruptible transportation or storage under interruptible transportation and storage contracts—an integrated package of services typically constituting a single performance obligation once scheduled, which includes receiving, transporting or storing (as applicable), and redelivering commodities.

In situations where, in our judgment, we consider the integrated package of services as a single performance obligation, which represents a majority of our interstate natural gas pipeline contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to stand ready (with regard to firm transportation and storage contracts), receive, transport or store, and redeliver natural gas to the customer; therefore, revenue is recognized over time upon satisfaction of our daily stand ready performance obligation.

We recognize revenues for reservation charges over the performance obligation period, which is the contract term, regardless of the volume of natural gas that is transported or stored. Revenues for commodity charges from both firm and interruptible transportation services and storage services are recognized when natural gas is delivered at the agreed upon delivery point or when natural gas is injected or withdrawn from the storage facility because they specifically relate to our efforts to provide these distinct services. Generally, reservation charges and commodity charges in our interstate natural gas pipeline businesses are recognized as revenue in the same period they are invoiced to our customers. As a result of the ratemaking process, certain amounts collected by us may be subject to refund upon the issuance of final orders by the FERC in pending rate proceedings. We use judgment to record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel, and other risks.

Midstream businesses: Revenues from our non-regulated gathering, processing, transportation, and storage midstream businesses include contracts for natural gas gathering, processing, treating, compression, transportation, and other related services with contract terms that are generally long-term in nature and may extend up to the production life of the associated reservoir. Additionally, our midstream businesses generate revenues from fees charged for storing customers’ natural gas and NGLs, generally under prepaid contracted storage capacity contracts. In situations where, in our judgment, we provide an integrated package of services combined into a single performance obligation, which represents a majority of this class of contracts with customers, we do not consider there to be multiple performance obligations because the nature of the overall promise in the contract is to provide gathering, processing, transportation, storage, and related services resulting in the delivery, or redelivery in the context of storage services, of pipeline-quality natural gas and NGLs to the customer. As such, revenue is recognized at the daily completion of the integrated package of services as the integrated package represents a single performance obligation. Additionally, certain contracts in our midstream businesses contain fixed or upfront payment terms that result in the deferral of revenues until such services have been performed or such capacity has been made available.

We also earn revenues from offshore crude oil and natural gas gathering and transportation and offshore production handling. These services represent an integrated package of services and are considered a single distinct performance obligation for which we recognize revenues as the services are provided to the customer.

We generally earn a contractually stated fee per unit for the volume of product transported, gathered, processed, or stored. The rate is generally fixed; however, certain contracts contain variable rates that are subject to change based on commodity prices, levels of throughput, or an annual adjustment based on a formulaic cost of service calculation. In addition, we have contracts with contractually stated fees that decline over the contract term, such as declines based on the passage of time periods or achievement of cumulative throughput amounts. For all of our contracts, we allocate the transaction price to each performance obligation based on the judgmentally determined relative standalone selling price. The excess of consideration received over revenue recognized results in the deferral of those amounts until future periods based on a units of production or straight-line methodology as these methods appropriately match the consumption of services provided to the customer. The units of production methodology requires the use of production estimates that are uncertain and the use of judgment when developing estimates of future production volumes, thus impacting the rate of revenue recognition. Production estimates are monitored as circumstances and events warrant. Certain of our gas gathering and processing agreements have minimum volume commitments (MVC). If a customer under such an agreement fails to meet its MVC for a specified period (thus not exercising all the contractual rights to gathering and processing services within the specified period, herein referred to as “breakage”), it is obligated to pay a contractually determined fee based upon the shortfall between the actual gathered or processed volumes and the MVC for the period contained in the contract. When we conclude, based on management’s judgment, it is probable that the customer will not exercise all or a portion of its remaining rights, we recognize revenue associated with such breakage amount in proportion to the pattern of exercised rights within the respective MVC period.

Under keep-whole and percent-of-liquids processing contracts, we receive commodity consideration in the form of NGLs and take title to the NGLs at the tailgate of the plant. We recognize such commodity consideration as service revenue based on the market value of the NGLs retained at the time the processing is provided. The current market value, as opposed to the market value at the contract inception date, is used due to a combination of factors, including the fact that the volume, mix, and market price of NGL consideration to be received is unknown at the time of contract execution and is not specified in our contracts with customers. Additionally, product sales revenue (discussed below) is recognized upon the sale of the NGLs to a third party based on the sales price at the time of sale. As a result, revenue is recognized in our Consolidated Statement of Income both at the time the processing service is provided in Service revenues – commodity consideration and at the time the NGLs retained as part of the processing service are sold in Product sales. The recognition of revenue related to commodity consideration has the impact of increasing the book value of NGL inventory, resulting in higher cost of goods sold at the time of sale.

Product Sales

In the course of providing transportation services to customers of our gas pipeline businesses and gathering and processing services to customers of our midstream businesses, we may receive different quantities of natural gas from customers than the quantities delivered on behalf of those customers. The resulting imbalances are primarily settled through the purchase or sale of natural gas with each customer under terms provided for in our FERC tariffs or gathering and processing agreements, respectively. Revenue is recognized from the sale of natural gas upon settlement of imbalances.

In certain instances, we purchase NGLs, crude oil, and natural gas from our oil and natural gas producer customers which we remarket. In addition, we retain NGLs as consideration in certain processing arrangements, as discussed above in the Service Revenues - Midstream businesses section. We also market natural gas and NGLs from the production at our upstream properties. We recognize revenue from the sale of these commodities when the products have been sold and delivered. Our product sales contracts are primarily short-term contracts based on prevailing market rates at the time of the transaction.

We purchase natural gas for storage when the current market price paid to buy and transport natural gas plus the cost to store and finance the natural gas is less than an estimated, forward market price that can be received in the future, resulting in positive net product sales. Commodity-based exchange-traded futures

contracts and over-the-counter (OTC) contracts are used to sell natural gas at that future price to substantially protect the natural gas revenues that will ultimately be realized when the stored natural gas is sold. Additionally, we enter into transactions to secure transportation capacity between delivery points in order to serve our customers and various markets.

The physical purchase, transportation, storage, and sale of natural gas are accounted for on a weighted-average cost or accrual basis, as appropriate, unlike the fair value basis utilized for the derivatives used to mitigate the natural gas price risk associated with the storage and transportation portfolio. Monthly demand charges are incurred for the contracted storage and transportation capacity and payments associated with asset management agreements, and these demand charges and payments are recognized in our Consolidated Statement of Income in the period they are incurred.

As we are acting as an agent for our natural gas marketing customers and engage in energy trading activities, our natural gas marketing revenues are presented net of the related costs of those activities. Prior to the 2022 integration of our legacy gas marketing operations with the acquired Sequent Acquisition operations (see Note 3 – Acquisitions), our legacy gas marketing operations were reported on a gross basis.

Contract Assets

Our contract assets primarily consist of revenue recognized under contracts containing MVC features whereby management has concluded it is probable there will be a short-fall payment at the end of the current MVC period, which typically follows the calendar year, and that a significant reversal of revenue recognized currently for the future MVC payment will not occur. As a result, our contract assets related to our future MVC payments are generally expected to be collected within the next 12 months and are included within Other current assets and deferred charges in our Consolidated Balance Sheet until such time as the MVC short-fall payments are invoiced to the customer.

Contract Liabilities

Our contract liabilities consist of advance payments primarily from midstream business customers which include construction reimbursements, prepayments, and other billings and transactions for which future services are to be provided under the contract. These amounts are deferred until recognized in revenue when the associated performance obligation has been satisfied, which is primarily based on a units of production methodology over the remaining contractual service periods, and are classified as current or noncurrent according to when such amounts are expected to be recognized. Current and noncurrent contract liabilities are included within Accrued and other current liabilities and Regulatory liabilities, deferred income, and other, respectively, in our Consolidated Balance Sheet.

Contracts requiring advance payments and the recognition of contract liabilities are evaluated to determine whether the advance payments provide us with a significant financing benefit. This determination is based on the combined effect of the expected length of time between when we transfer the promised good or service to the customer, when the customer pays for those goods or services, and the prevailing interest rates. We have assessed our contracts for significant financing components and determined, in our judgment, that one group of contracts entered into in contemplation of one another for certain capital reimbursements contains a significant financing component. As a result, we recognize noncash interest expense based on the effective interest method and revenue (noncash) is recognized when the underlying asset is placed into service utilizing a units of production or straight-line methodology over the life of the corresponding customer contract.

Derivative instruments and hedging activities [Policy Text Block]

Derivative instruments and hedging activities

We are exposed to commodity price risk. We utilize derivatives to manage a portion of our commodity price risk. These instruments consist primarily of swaps, futures, and forward contracts involving short- and long-term purchases and sales of energy commodities. We purchase natural gas for storage when the current market price paid

to buy and transport natural gas plus the cost to store and finance the natural gas is less than an estimated, forward market price that can be received in the future. Additionally, we enter into transactions to secure transportation capacity between delivery points in order to serve our customers and various markets. Commodity-based exchange-traded futures contracts and OTC contracts are used to capture the price differential or spread between the locations served by the capacity in order to substantially protect the natural gas revenues that will ultimately be realized when the physical flow of natural gas between receipt and delivery points occurs. Some commodity-related derivative contracts require physical delivery as opposed to financial settlement, and this type of derivative is both common and prevalent within the natural gas marketing operations. These contracts generally meet the definition of derivatives and are typically not designated as hedges for accounting purposes. When a commodity-related derivative contract is settled physically, any cumulative unrealized gain or loss is reversed, and the contract price is recognized in the respective line item in our Consolidated Statement of Income representing the actual price of the underlying goods being delivered.

Unrealized gains and losses on physically settled commodity-related derivative contracts for commodity sales transactions are recognized in Net gain (loss) on commodity derivatives in our Consolidated Statement of Income. Realized and unrealized gains and losses on non-designated commodity-related derivative contracts for commodity sales transactions that are financially settled are reported in Net gain (loss) on commodity derivatives in our Consolidated Statement of Income. Net gains and losses on derivatives for shrink gas purchases for processing plants are reported in Net processing commodity expenses in our Consolidated Statement of Income.

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. (See Note 16 – Derivatives.)

We report the fair value of derivatives, except those for which the normal purchases and normal sales exception has been elected, in Derivative assets; Regulatory assets, deferred charges, and other; Derivative liabilities; or Regulatory liabilities, deferred income, and other in our Consolidated Balance Sheet. These amounts are presented on a net basis and reflect the netting of asset and liability positions permitted under the terms of master netting arrangements and cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. We determine the current and noncurrent classification based on the timing of expected future cash flows of individual trades.

The accounting for the changes in fair value of a commodity derivative can be summarized as follows:

Derivative Treatment	Accounting Method
Normal purchases and normal sales exception	Accrual accounting
Designated in a qualifying hedging relationship	Hedge accounting
All other derivatives	Mark-to-market accounting

We may elect the normal purchases and normal sales exception for certain short- and long-term purchases and sales of physical energy commodities. Under accrual accounting, any change in the fair value of these derivatives is not reflected in our Consolidated Balance Sheet after the initial election of the exception.

We may also designate a hedging relationship for certain commodity derivatives. For a derivative to qualify for designation in a hedging relationship, it must meet specific criteria and we must maintain appropriate documentation. We establish hedging relationships pursuant to our risk management policies. We evaluate the hedging relationships at the inception of the hedge and on an ongoing basis to determine whether the hedging relationship is, and is expected to remain, highly effective in achieving offsetting changes in fair value or cash flows attributable to the underlying risk being hedged. We also regularly assess whether the hedged forecasted transaction is probable of occurring. If a derivative ceases to be or is no longer expected to be highly effective, or if we believe

the likelihood of occurrence of the hedged forecasted transaction is no longer probable, hedge accounting is discontinued prospectively, and future changes in the fair value of the derivative are recognized currently in Net gain (loss) on commodity derivatives in our Consolidated Statement of Income.

For commodity derivatives designated as a cash flow hedge, the change in fair value of the derivative is reported in Accumulated other comprehensive income (loss) (AOCI) in our Consolidated Balance Sheet and reclassified into earnings in the period in which the hedged item affects earnings. Gains or losses deferred in AOCI associated with terminated derivatives, derivatives that cease to be highly effective hedges, derivatives for which the forecasted transaction is reasonably possible but no longer probable of occurring, and cash flow hedges that have been otherwise discontinued remain in AOCI until the hedged item affects earnings. If it becomes probable that the forecasted transaction designated as the hedged item in a cash flow hedge will not occur, any gain or loss deferred in AOCI is recognized in Net gain (loss) on commodity derivatives in our Consolidated Statement of Income at that time. The change in likelihood of a forecasted transaction is a judgmental decision that includes qualitative assessments made by us. As of December 31, 2022 and 2021, we are not applying hedge accounting to any commodity derivative instruments.

Interest capitalized [Policy Text Block]

Interest capitalized

We capitalize interest during construction on major projects with construction periods of at least 3 months and a total project cost in excess of $1 million. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds (equity AFUDC). The latter is included in Other income (expense) – net below Operating income (loss) in our Consolidated Statement of Income. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by nonregulated companies are based on our average interest rate on debt.

Income taxes [Policy Text Block]

Income taxes

We include the operations of our domestic corporate subsidiaries and income from our subsidiary partnerships in our consolidated federal income tax return and also file tax returns in various foreign and state jurisdictions as required. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of our assets and liabilities. Our judgment and income tax assumptions are used to determine the levels, if any, of valuation allowances associated with deferred tax assets.

Earnings (loss) per common share [Policy Text Block]

Earnings (loss) per common share

Basic earnings (loss) per common share in our Consolidated Statement of Income is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock units. Diluted earnings (loss) per common share in our Consolidated Statement of Income primarily includes any dilutive effect of nonvested restricted stock units and stock options. Diluted earnings (loss) per common share is calculated using the treasury-stock method.

Cash and cash equivalents [Policy Text Block]

Cash and cash equivalents

Cash and cash equivalents in our Consolidated Balance Sheet consist of highly liquid investments with original maturities of three months or less when acquired.

Accounts receivable [Policy Text Block]

Accounts receivable

Accounts receivable are carried on a gross basis, with no discounting, less an allowance for doubtful accounts. We estimate the allowance for doubtful accounts, considering current expected credit losses using a forward-looking “expected loss” model, the financial condition of our customers, and the age of past due accounts. The majority of our trade receivable balances are due within 30 days. We monitor the credit quality of our counterparties through review of collection trends, credit ratings, and other analyses, such as bankruptcy monitoring. Financial assets from our natural gas transmission and storage business, gathering, processing and transportation business, marketing

business, and upstream operations are segregated into separate pools for evaluation due to different counterparty risks inherent in each business. Changes in counterparty risk factors could lead to reassessment of the composition of our financial assets as separate pools or the need for additional pools. We calculate our allowance for credit losses incorporating an aging method. In estimating our expected credit losses, we utilize historical loss rates over many years, which include periods of both high and low commodity prices. Commodity prices could have a significant impact on a portion of our gathering and processing and upstream counterparties’ financial health and ability to satisfy current obligations. Our expected credit loss estimate considers both internal and external forward-looking commodity price expectations, as well as counterparty credit ratings, and factors impacting their near-term liquidity. In addition, our expected credit loss estimate considers potential contractual, physical, and commercial protections and outcomes in the case of a counterparty bankruptcy. The physical location and nature of our services help to mitigate collectability concerns of our gathering and processing producer customers. Our gathering lines in many cases are physically connected to the customers’ wellheads and pads, and there may not be alternative gathering lines nearby. The construction of gathering systems is capital intensive and it would be costly for others to replicate, especially considering the depletion to date of the associated reserves. As a result, we play a critical role in getting customers’ production from the wellhead to a marketable condition and location. This tends to reduce collectability risk as our services enable producers to generate operating cash flows. Commodity price movements generally do not impact the majority of our natural gas transmission businesses customers’ financial condition.

We also provide marketing and risk management services to retail and wholesale gas marketers, utility companies, upstream producers, and industrial customers. These counterparties utilize netting agreements that enable us to net receivables and payables by counterparty upon settlement. We also net across product lines and against cash collateral received to collateralize receivable positions, provided the netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, our counterparties are settled net, they are recorded on a gross basis in our Consolidated Balance Sheet as accounts receivable and accounts payable.

We do not offer extended payment terms and typically receive payment within one month. We consider receivables past due if full payment is not received by the contractual due date. Interest income related to past due accounts receivable is generally recognized at the time full payment is received or collectability is assured. Past due accounts are generally written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. We do not have a material amount of significantly aged receivables at December 31, 2022 and 2021.

Inventories [Policy Text Block]

Inventories

Inventories in our Consolidated Balance Sheet primarily consist of natural gas in underground storage, NGLs, and materials and supplies and primarily are stated at the lower of cost or net realizable value. The cost of inventories is primarily determined using the average-cost method. Any lower of cost or net realizable value adjustments are included in Product sales (for natural gas marketing inventory as these sales are presented net of the related costs) or in Product costs for NGL inventory.

Property, plant, and equipment [Policy Text Block]

Property, plant, and equipment

Property, plant, and equipment is initially recorded at cost. We base the carrying value of these assets on estimates, assumptions, and judgments relative to capitalized costs, useful lives, and salvage values.

As regulated entities, Northwest Pipeline and Transco provide for depreciation using the straight-line method at FERC-prescribed rates. Depreciation for nonregulated entities is provided primarily on the straight-line method over estimated useful lives, except for certain offshore facilities that apply an accelerated depreciation method.

We follow the successful efforts method of accounting for our undivided interest in upstream properties. Our oil and gas producing property costs are depreciated using a units of production method.

Gains or losses from the ordinary sale or retirement of property, plant, and equipment for regulated pipelines are credited or charged to accumulated depreciation. Gains or losses from the ordinary sale or retirement of property,

plant, and equipment for nonregulated assets are primarily recorded in Other (income) expense – net included in Operating income (loss) in our Consolidated Statement of Income.

Ordinary maintenance and repair costs are generally expensed as incurred. Costs of major renewals and replacements are capitalized as property, plant, and equipment.

We record a liability and increase the basis in the underlying asset for the present value of each expected future ARO at the time the liability is initially incurred, typically when the asset is acquired or constructed. For our upstream properties, the ARO is recorded based on our working interest in the underlying properties. As regulated entities, Northwest Pipeline and Transco offset the depreciation of the underlying asset that is attributable to capitalized ARO cost to a regulatory asset as we expect to recover these amounts in future rates. We measure changes in the liability due to passage of time by applying an interest rate to the liability balance. This amount is recognized as an increase in the carrying amount of the liability and as a corresponding accretion expense included in Operating and maintenance expenses in our Consolidated Statement of Income, except for regulated entities, for which the increase in the liability results in a corresponding increase to a regulatory asset. The regulatory asset is amortized commensurate with our collection of those costs in rates.

Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium.

Intangible assets [Policy Text Block]

Intangible assets

Our intangible assets included within Intangible assets – net of accumulated amortization in our Consolidated Balance Sheet are primarily related to gas gathering, processing, and fractionation customer relationships. Our intangible assets are generally amortized on a straight-line basis over the period in which these assets contribute to our cash flows. We evaluate these assets for changes in the expected remaining useful lives and would reflect any changes prospectively through amortization over the revised remaining useful life.

Impairment of property, plant, and equipment, intangible assets, and investments [Policy Text Block]

Impairment of property, plant, and equipment, intangible assets, and investments

We evaluate our property, plant, and equipment and intangible assets for impairment when, in our judgment, events or circumstances, including probable abandonment, indicate that the carrying value of such assets may not be recoverable. When an indicator of impairment has occurred, we compare our estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred and we may apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes, including selling the assets in the near term or holding them for their remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment to be recognized in our consolidated financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. This evaluation is performed at the lowest level for which separately identifiable cash flows exist.

For assets identified to be disposed of in the future and considered held for sale, we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change.

We evaluate our investments for impairment when, in our judgment, events or circumstances indicate that the carrying value of such investments may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, we compare our estimate of fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and we consider the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in our consolidated financial statements as an impairment charge.

Judgment and assumptions are inherent in our estimate of undiscounted future cash flows and an asset’s or investment’s fair value. Additionally, judgment is used to determine the probability of sale with respect to assets considered for disposal.

Equity-method investment basis differences [Policy Text Block]

Equity-method investment basis differences

Differences between the carrying value of our equity-method investments and our underlying equity in the net assets of investees are accounted for as if the investees were consolidated subsidiaries. Equity earnings (losses) in our Consolidated Statement of Income includes our allocable share of net income (loss) of investees adjusted for any depreciation and amortization, as applicable, associated with basis differences.

Leases [Policy Text Block]

Leases

We recognize a lease liability with an offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases based on the present value of the future lease payments. We have elected to combine lease and nonlease components for all classes of leased assets in our calculation of the lease liability and the offsetting right-of-use asset.

Our lease agreements require both fixed and variable periodic payments, with initial terms typically ranging from one year to 20 years. Payment provisions in certain of our lease agreements contain escalation factors which may be based on stated rates or a change in a published index at a future time. The amount by which a lease escalates based on the change in a published index, which is not known at lease commencement, is considered a variable payment and is not included in the present value of the future lease payments, which only includes those that are stated or can be calculated based on the lease agreement at lease commencement. In addition to the noncancellable periods, many of our lease agreements provide for one or more extensions of the lease agreement for periods ranging from one year in length to an indefinite number of times following the specified contract term. Other lease agreements provide for extension terms that allow us to utilize the identified leased asset for an indefinite period of time so long as the asset continues to be utilized in our operations. In consideration of these renewal features, we assess the term of the lease agreements, which includes using judgment in the determination of which renewal periods and termination provisions, when at our sole election, will be reasonably certain of being exercised. Periods after the initial term or extension terms that allow for either party to the lease to cancel the lease are not considered in the assessment of the lease term. Additionally, we have elected to exclude leases with an original term of one year or less, including renewal periods, from the calculation of the lease liability and the offsetting right-of-use asset.

We use judgment in determining the discount rate upon which the present value of the future lease payments is determined. This rate is based on a collateralized interest rate corresponding to the term of the lease agreement using company, industry, and market information available.

When permitted under our lease agreements, we may sublease certain unused office space for fixed periods that could extend up to the length of the original lease agreement.

Pension and other postretirement benefits [Policy Text Block]

Pension and other postretirement benefits

The funded status of each of the pension and other postretirement benefit plans is recognized separately in our Consolidated Balance Sheet as either an asset or liability. The plans’ benefit obligations and net periodic benefit costs (credits) are actuarially determined and impacted by various assumptions and estimates.

The discount rates are determined separately for each of our pension and other postretirement benefit plans based on an approach specific to our plans. The year-end discount rates are determined considering a yield curve comprised of high-quality corporate bonds and the timing of the expected benefit cash flows of each plan.

The expected long-term rates of return on plan assets are determined by combining a review of the historical returns within the portfolio, the investment strategy included in the plans’ investment policy statement, and capital

market projections for the asset classes in which the portfolio is invested, as well as the weighting of each asset class.

Unrecognized actuarial gains and losses are deferred and recorded in AOCI or, for Transco and Northwest Pipeline, as a regulatory asset or liability, until amortized as a component of net periodic benefit cost (credit). The unrecognized net actuarial losses deferred in AOCI at December 31, 2022 and 2021 were $18 million and $30 million, respectively. Unrecognized actuarial gains and losses in excess of 10 percent of the greater of the benefit obligation or the market-related value of plan assets are amortized over the participants’ average remaining future years of service, which is approximately 10 years for our pension plans and approximately 5 years for our other postretirement benefit plan.

The expected return on plan assets component of net periodic benefit cost (credit) is calculated using the market-related value of plan assets. For our pension plans, the market-related value of plan assets is equal to the fair value of plan assets adjusted to reflect the amortization of gains or losses associated with the difference between the expected and actual return on plan assets over a 5-year period. Additionally, the market-related value of assets may be no more than 110 percent or less than 90 percent of the fair value of plan assets at the beginning of the year. The market-related value of plan assets for our other postretirement benefit plan is equal to the unadjusted fair value of plan assets at the beginning of the year.

Contingent liabilities [Policy Text Block]

Contingent liabilities

We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable, and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates.

Treasury stock [Policy Text Block]

Treasury stock

Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as Treasury stock, at cost in our Consolidated Balance Sheet. Gains and losses on the subsequent reissuance of shares are credited or charged to Capital in excess of par value in our Consolidated Balance Sheet using the average-cost method.

Cash flows from revolving credit facility and commercial paper program [Policy Text Block]

Cash flows from revolving credit facility and commercial paper program

Proceeds and payments related to borrowings under our revolving credit facility are reflected in the financing activities in our Consolidated Statement of Cash Flows on a gross basis. Proceeds and payments related to borrowings under our commercial paper program are reflected in the financing activities in our Consolidated Statement of Cash Flows on a net basis, as the outstanding notes generally have maturity dates less than three months from the date of issuance. (See Note 12 – Debt and Banking Arrangements.)

XML

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Regulatory Assets and Liabilities [Table Text Block]

Our current and noncurrent regulatory asset and liability balances at December 31, 2022 and 2021 are as follows:

	December 31,
	2022		2021
	(Millions)
Current assets reported within Other current assets and deferred charges	$	138	$	111
Noncurrent assets reported within Regulatory assets, deferred charges, and other	459		415
Total regulated assets	$	597	$	526
Current liabilities reported within Accrued and other current liabilities	$	201	$	56
Noncurrent liabilities reported within Regulatory liabilities, deferred income, and other	1,233		1,324
Total regulated liabilities	$	1,434	$	1,380

XML

Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2022

Variable Interest Entity Disclosures [Abstract]

Schedule of Variable Interest Entities [Table Text Block]

The following table presents amounts included in the Consolidated Balance Sheet that are only for the use or obligation of our consolidated VIEs:

	December 31,
	2022		2021
	(Millions)
Assets (liabilities):
Cash and cash equivalents	$	49	$	78
Trade accounts and other receivables – net	136		132
Inventories	4		3
Other current assets and deferred charges	7		7
Property, plant, and equipment – net	5,154		5,295
Intangible assets – net of accumulated amortization	2,158		2,267
Regulatory assets, deferred charges, and other	29		20
Accounts payable	(76)		(61)
Accrued and other current liabilities	(34)		(29)
Regulatory liabilities, deferred income, and other	(275)		(287)

XML

Acquisitions (Tables)

12 Months Ended

Dec. 31, 2022

Business Acquisition [Line Items]

Business Acquisition, Pro Forma Information [Table Text Block]

The following pro forma Revenues and Net income (loss) attributable to The Williams Companies, Inc. in 2022, 2021, and 2020, are presented as if the Trace Acquisition had been completed on January 1, 2021, and the Sequent Acquisition had been completed on January 1, 2020. These pro forma amounts are not necessarily indicative of what the actual results would have been if the Trace Acquisition and Sequent Acquisition had in fact occurred on the dates or for the periods indicated, nor do they purport to project Revenues or Net income (loss) attributable to The Williams Companies, Inc. for any future periods or as of any date. These amounts do not give effect to any potential cost savings, operating synergies, or revenue enhancements to result from the transaction or the potential costs to achieve these cost savings, operating synergies, and revenue enhancements.

	Year Ended December 31, 2022
	As Reported		Pro Forma Trace (1)				Pro Forma Combined
	(Millions)
Revenues	$	10,965	$	45			$	11,010
Net income (loss) attributable to The Williams Companies, Inc.	2,049		18				2,067
	Year Ended December 31, 2021
	As Reported		Pro Forma Trace		Pro Forma Sequent (2)		Pro Forma Combined
	(Millions)
Revenues	$	10,627	$	118	$	188	$	10,933
Net income (loss) attributable to The Williams Companies, Inc.	1,517		42		4		1,563
	Year Ended December 31, 2020
	As Reported				Pro Forma Sequent		Pro Forma Combined
	(Millions)
Revenues	$	7,719			$	74	$	7,793
Net income (loss) attributable to The Williams Companies, Inc.	211				(13)		198

(1)Excludes results from operations acquired in the Trace Acquisition for the period beginning on the acquisition date of April 29, 2022, as these results are included in the amounts as reported.

(2)Excludes results from operations acquired in the Sequent Acquisition for the period beginning on the acquisition date of July 1, 2021, as these results are included in the amounts as reported.

Trace Midstream Acquisition

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in the West segment, and liabilities assumed at April 29, 2022. The fair value of accounts receivable acquired equals contractual amounts receivable.

	(Millions)
Cash and cash equivalents	$	39
Trade accounts and other receivables – net	18
Property, plant, and equipment – net	448
Intangible assets – net of accumulated amortization	472
Other noncurrent assets	20
Total assets acquired	$	997
Accounts payable	$	12
Accrued and other current liabilities	5
Other noncurrent liabilities	8
Total liabilities assumed	$	25
Net assets acquired	$	972

Sequent Acquisition

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

We accounted for the Sequent Acquisition as a business combination. The following table presents the allocation of the acquisition date fair value of the major classes of the assets acquired, which are presented in the Gas & NGL Marketing Services segment, and liabilities assumed at July 1, 2021. The fair value of accounts receivable acquired equals contractual amounts receivable. The fair value of the intangible assets was measured using an income approach. The fair value of the inventory acquired was based on the market price of the natural gas in underground storage at the acquisition date. See Note 15 – Fair Value Measurements, Guarantees, and Concentration of Credit Risk for the valuation techniques used to measure fair value of derivative assets and liabilities.

	(Millions)
Cash and cash equivalents	$	8
Trade accounts and other receivables – net	498
Inventories	121
Derivative assets	57
Other current assets and deferred charges	4
Property, plant, and equipment – net	5
Intangible assets – net of accumulated amortization	306
Other noncurrent assets	3
Commodity derivatives included in other noncurrent assets	49
Total assets acquired	$	1,051
Accounts payable	$	514
Derivative liabilities	116
Accrued and other current liabilities	46
Other noncurrent liabilities	1
Commodity derivatives included in other noncurrent liabilities	215
Total liabilities assumed	$	892
Net assets acquired	$	159

XML

Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2022

Revenue Recognition [Abstract]

Disaggregation of Revenue [Table Text Block]

The following table presents our revenue disaggregated by major service line:

	Transco		Northwest Pipeline		Gulf of Mexico Midstream and Storage		Northeast Midstream		West Midstream		Gas & NGL Marketing Services		Other		Eliminations		Total
	(Millions)
2022
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	2,696	$	443	$	—	$	—	$	—	$	—	$	—	$	(72)	$	3,067
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		365		1,395		1,476		—		—		(164)		3,072
Commodity consideration	—		—		64		14		182		—		—		—		260
Other	10		—		27		233		54		3		—		(19)		308
Total service revenues	2,706		443		456		1,642		1,712		3		—		(255)		6,707
Product sales	179		—		251		134		841		10,768		706		(1,813)		11,066
Total revenues from contracts with customers	2,885		443		707		1,776		2,553		10,771		706		(2,068)		17,773
Other revenues (1)	24		4		10		26		8		7,929		(55)		(11)		7,935
Other adjustments (2)	—		—		—		—		—		(15,467)		—		724		(14,743)
Total revenues	$	2,909	$	447	$	717	$	1,802	$	2,561	$	3,233	$	651	$	(1,355)	$	10,965
2021
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	2,547	$	441	$	—	$	—	$	—	$	—	$	—	$	(33)	$	2,955
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		344		1,308		1,184		—		—		(130)		2,706
Commodity consideration	—		—		52		7		179		—		—		—		238
Other	10		—		22		195		52		3		1		(19)		264
Total service revenues	2,557		441		418		1,510		1,415		3		1		(182)		6,163
Product sales	88		—		269		99		643		6,404		333		(1,215)		6,621
Total revenues from contracts with customers	2,645		441		687		1,609		2,058		6,407		334		(1,397)		12,784
Other revenues (1)	10		3		8		25		(32)		2,632		11		(13)		2,644
Other adjustments (2)	—		—		—		—		—		(4,828)		—		27		(4,801)
Total revenues	$	2,655	$	444	$	695	$	1,634	$	2,026	$	4,211	$	345	$	(1,383)	$	10,627

	Transco		Northwest Pipeline		Gulf of Mexico Midstream and Storage		Northeast Midstream		West Midstream		Gas & NGL Marketing Services		Other		Eliminations		Total
	(Millions)
2020
Revenues from contracts with customers:
Service revenues:
Regulated interstate natural gas transportation and storage	$	2,404	$	449	$	—	$	—	$	—	$	—	$	—	$	(7)	$	2,846
Gathering, processing, transportation, fractionation, and storage:
Monetary consideration	—		—		348		1,279		1,226		—		—		(97)		2,756
Commodity consideration	—		—		21		7		101		—		—		—		129
Other	10		—		27		164		35		32		1		(16)		253
Total service revenues	2,414		449		396		1,450		1,362		32		1		(120)		5,984
Product sales	80		—		114		57		152		1,602		—		(336)		1,669
Total revenues from contracts with customers	2,494		449		510		1,507		1,514		1,634		1		(456)		7,653
Other revenues (1)	10		—		9		22		9		(3)		33		(14)		66
Total revenues	$	2,504	$	449	$	519	$	1,529	$	1,523	$	1,631	$	34	$	(470)	$	7,719

______________________________

(1)Revenues not derived from contracts with customers primarily consist of physical product sales related to derivative contracts, realized and unrealized gains and losses associated with our derivative contracts, which are reported in Net gain (loss) on commodity derivatives in the Consolidated Statement of Income, management fees that we receive for certain services we provide to operated equity-method investments, and leasing revenues associated with our headquarters building.

(2)Other adjustments reflect certain costs of Gas & NGL Marketing Services’ risk management activities. As we are acting as agent for natural gas marketing customers or engage in energy trading activities, the resulting revenues are presented net of the related costs of those activities in the Consolidated Statement of Income (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).

Contract with Customer, Asset and Liability [Table Text Block]

Contract Assets

The following table presents a reconciliation of our contract assets:

	Year Ended December 31,
	2022		2021
	(Millions)
Balance at beginning of year	$	22	$	12
Revenue recognized in excess of amounts invoiced	208		184
Minimum volume commitments invoiced	(201)		(174)
Balance at end of year	$	29	$	22

Contract Liabilities

The following table presents a reconciliation of our contract liabilities:

	Year Ended December 31,
	2022		2021
	(Millions)
Balance at beginning of year	$	1,126	$	1,209
Payments received and deferred	180		116
Significant financing component	9		10
Contract liability acquired	2		1
Recognized in revenue	(274)		(210)
Balance at end of year	$	1,043	$	1,126

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]

The following table presents the amount of the contract liabilities balance expected to be recognized as revenue when performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of December 31, 2022.

	Contract Liabilities		Remaining Performance Obligations
	(Millions)
2023 (one year)	$	142	$	3,643
2024 (one year)	122		3,388
2025 (one year)	117		3,149
2026 (one year)	112		2,520
2027 (one year)	101		2,415
Thereafter	449		14,675
Total	$	1,043	$	29,790

XML

Provision (Benefit) for Income Taxes (Tables)

12 Months Ended

Dec. 31, 2022

Income Tax Expense (Benefit), Continuing Operations [Abstract]

Schedule of Components of Provision (benefit) for income taxes [Table Text Block]

The Provision (benefit) for income taxes includes:

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Current:
Federal	$	(25)	$	(1)	$	(29)
State	19		3		—
	(6)		2		(29)
Deferred:
Federal	424		421		98
State	7		88		10
	431		509		108
Provision (benefit) for income taxes	$	425	$	511	$	79

Provision for income taxes at federal statutory rate [Table Text Block]

Reconciliations from the Provision (benefit) at statutory rate to recorded Provision (benefit) for income taxes are as follows:

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Provision (benefit) at statutory rate	$	534	$	435	$	58
Increases (decreases) in taxes resulting from:
State income taxes (net of federal benefit)	113		71		6
State deferred income tax rate change	(92)		—		—
Federal valuation allowance	(70)		3		1
Federal settlements	(45)		—		—
Impact of nontaxable noncontrolling interests	(14)		(9)		3
Other – net	(1)		11		11
Provision (benefit) for income taxes	$	425	$	511	$	79

Deferred tax liabilities and Deferred tax assets [Table Text Block]

Significant components of Deferred income tax liabilities are as follows:

	December 31,
	2022		2021
	(Millions)
Gross deferred income tax liabilities:
Property, plant and equipment	$	3,171	$	2,777
Investments	1,784		1,669
Other	138		154
Total gross deferred income tax liabilities	5,093		4,600
Gross deferred income tax assets:
Accrued liabilities	1,108		872
Foreign tax credits	91		140
Federal loss carryovers	730		879
State losses and credits	356		421
Other	121		132
Total gross deferred income tax assets	2,406		2,444
Less valuation allowance	200		297
Net deferred income tax assets	2,206		2,147
Deferred income tax liabilities	$	2,887	$	2,453

XML

Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2022

Retirement Benefits [Abstract]

Changes in Projected Benefit Obligations, Fair Value of Plan Assets, Funded Status, and Schedule of Amounts Recognized in Balance Sheet [Table Text Block]

The following table presents the changes in benefit obligations and plan assets for pension benefits and other postretirement benefits for the years indicated:

	Pension Benefits				Other Postretirement Benefits
	2022		2021		2022		2021
	(Millions)
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,133	$	1,183	$	200	$	220
Service cost	28		30		1		1
Interest cost	31		28		6		5
Plan participants’ contributions	—		—		2		2
Benefits paid	(78)		(83)		(12)		(14)
Net actuarial loss (gain) (1)	(162)		(21)		(45)		(14)
Settlements	(12)		(4)		—		—
Net increase (decrease) in benefit obligation	(193)		(50)		(48)		(20)
Benefit obligation at end of year	940		1,133		152		200
Change in plan assets:
Fair value of plan assets at beginning of year	1,336		1,357		287		278
Actual return on plan assets	(132)		62		(27)		16
Employer contributions	3		4		3		5
Plan participants’ contributions	—		—		2		2
Benefits paid	(78)		(83)		(12)		(14)
Settlements	(12)		(4)		—		—
Net increase (decrease) in fair value of plan assets	(219)		(21)		(34)		9
Fair value of plan assets at end of year	1,117		1,336		253		287
Funded status — overfunded (underfunded)	$	177	$	203	$	101	$	87
Amounts recognized in the Consolidated Balance Sheet:
Noncurrent assets	$	201	$	229	$	105	$	91
Current liabilities	(2)		(3)		(4)		(4)
Noncurrent liabilities	(22)		(23)		—		—
Funded status — overfunded (underfunded)	$	177	$	203	$	101	$	87
Accumulated benefit obligation	$	930	$	1,118

____________

(1)    2022 amounts are due primarily to the following factors: Pension benefits - discount rate assumptions, partially offset by change in interest crediting rate assumption; Other Postretirement Benefits - discount rate assumption. 2021 amounts are due primarily to the following factors: Pension Benefits - discount rate assumptions, partially offset by experience-related items; Other Postretirement Benefits - discount rate assumption and experience-related items.

Defined Benefit Plan, Plan with Projected Benefit Obligation in Excess of Plan Assets [Table Text Block]

The following table summarizes information for pension plans with obligations in excess of plan assets at December 31.

	2022		2021
	(Millions)
Projected benefit obligation	$	24	$	26
Accumulated benefit obligation	22		22
Fair value of plan assets	—		—

Pre-tax amounts recognized in Accumulated other comprehensive income (loss)[Table Text Block]

Pre-tax amounts recognized in Accumulated other comprehensive income (loss) at December 31 are as follows:

	Pension Benefits				Other Postretirement Benefits
	2022		2021		2022		2021
	(Millions)
Net actuarial gain (loss)	$	(45)	$	(46)	$	18	$	4

Schedule of Net Benefit Cost (Credit) [Table Text Block]

Net periodic benefit cost (credit) for the years ended December 31 consist of the following:

	Pension Benefits						Other Postretirement  Benefits
	2022		2021		2020		2022		2021		2020
	(Millions)
Components of net periodic benefit cost (credit):
Service cost	$	28	$	30	$	31	$	1	$	1	$	1
Interest cost	31		28		36		6		5		7
Expected return on plan assets	(44)		(43)		(53)		(10)		(10)		(11)
Amortization of net actuarial loss	12		14		21		—		—		—
Net actuarial loss from settlements	3		1		9		—		—		—
Reclassification to regulatory liability	—		—		—		1		2		2
Net periodic benefit cost (credit) (1)	$	30	$	30	$	44	$	(2)	$	(2)	$	(1)

____________

(1)    Components other than Service cost are included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Income.

Other changes in plan assets and benefit obligations recognized in other comprehensive income (loss) [Table Text Block]

Other changes in plan assets and benefit obligations recognized in Other comprehensive income (loss) before taxes for the years ended December 31 consist of the following:

	Pension Benefits						Other Postretirement  Benefits
	2022		2021		2020		2022		2021		2020
	(Millions)
Net actuarial gain (loss) arising during the year	$	(14)	$	40	$	112	$	14	$	29	$	(4)
Amortization of net actuarial loss	12		14		21		—		—		—
Net actuarial loss from settlements	3		1		9		—		—		—
Total recognized in Other comprehensive income (loss)	$	1	$	55	$	142	$	14	$	29	$	(4)

Defined Benefit Plan, Assumptions [Table Text Block]

The weighted-average assumptions utilized to determine benefit obligations and Net periodic benefit cost (credit) as of December 31 are as follows:

	Pension Benefits						Other Postretirement  Benefits
	2022		2021		2020		2022		2021		2020
Benefit obligations:
Discount rate	5.16	%	2.82	%	2.45	%	5.20	%	2.93	%	2.59	%
Rate of compensation increase	3.58		3.67		3.76		N/A		N/A		N/A
Cash balance interest crediting rate	3.50		3.00		3.00		N/A		N/A		N/A
Net periodic benefit cost (credit):
Discount rate	2.84	%	2.45	%	3.08	%	2.93	%	2.59	%	3.27	%
Expected long-term rate of return on plan assets	3.81		3.69		4.67		3.67		3.61		4.39
Rate of compensation increase	3.67		3.76		3.68		N/A		N/A		N/A
Cash balance interest crediting rate	3.00		3.00		3.50		N/A		N/A		N/A

Fair values of plan assets [Table Text Block]

The fair values of our pension and other postretirement benefits plan assets by asset class at December 31 are as follows: 

	2022
	Pension Benefits						Other Postretirement Benefits
	Level 1 (1)		Level 2 (2)		Total		Level 1 (1)		Level 2 (2)		Total
	(Millions)
Cash management funds	$	45	$	—	$	45	$	105	$	—	$	105
Government debt securities	58		18		76		8		3		11
Corporate debt securities	—		284		284		—		39		39
Other	1		4		5		—		—		—
	$	104	$	306	410		$	113	$	42	155
Commingled investment funds (3):
Equities					273						38
Fixed income					434						60
Total assets at fair value					$	1,117					$	253

	2021
	Pension Benefits						Other Postretirement Benefits
	Level 1 (1)		Level 2 (2)		Total		Level 1 (1)		Level 2 (2)		Total
	(Millions)
Cash management funds	$	37	$	—	$	37	$	14	$	—	$	14
Equity securities	42		19		61		39		10		49
Government debt securities	99		28		127		13		4		17
Corporate debt securities	—		350		350		—		47		47
Mutual fund - Municipal bonds	—		—		—		59		—		59
Other	(3)		2		(1)		(1)		—		(1)
	$	175	$	399	574		$	124	$	61	185
Commingled investment funds (3):
Equities					288						39
Fixed income					474						63
Total assets at fair value					$	1,336					$	287

____________

(1)    Level 1 includes assets with fair values based on quoted prices in active markets for identical assets. Cash management funds, equity securities traded on U.S. exchanges, U.S. Treasury securities, and mutual funds are included in this level.

(2)    Level 2 includes assets with fair values determined by using significant other observable inputs. This level includes equity securities traded on active foreign exchanges and fixed income securities, other than U.S. Treasury securities, that are valued primarily using pricing models which incorporate observable inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads.

(3)    The commingled investment funds are measured at fair value using net asset value per share. Certain standard withdrawal restrictions generally apply, which may include redemption notification period restrictions ranging from 1 day to 15 days.

Expected benefit payments [Table Text Block]

Following are the expected benefit payments, which reflect the same assumptions previously discussed and future service as appropriate.

	Pension Benefits		Other Postretirement Benefits
	(Millions)
2023	$	84	$	13
2024	83		13
2025	84		12
2026	81		12
2027	80		11
2028-2032	389		52

XML

Investing Activities (Tables)

12 Months Ended

Dec. 31, 2022

Investments [Abstract]

Investments [Table Text Block]

	Ownership Interest at December 31, 2022	December 31,
		2022		2021
		(Millions)
Equity method:
Appalachia Midstream Investments	(1)	$	2,975	$	3,056
RMM	50%	395		401
OPPL	50%	386		388
Blue Racer	50%	383		377
Discovery	60%	345		328
Gulfstream	50%	220		215
Laurel Mountain	69%	205		226
Other	Various	139		130
		5,048		5,121
Other		17		6
		$	5,065	$	5,127

___________

(1)Includes equity-method investments in multiple gathering systems in the Marcellus Shale region with an approximate average 66 percent interest.

Contributions [Table Text Block]

Purchases of and contributions to equity-method investments

We generally fund our portion of significant expansion or development projects of these investees through additional capital contributions. These transactions increased the carrying value of our investments and included:

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Appalachia Midstream Investments	$	83	$	84	$	116
Discovery	41		—		—
Cardinal Pipeline Company, LLC	16		—		—
Gulfstream	14		26		3
Blue Racer (1)	—		3		157
Other	12		2		49
	$	166	$	115	$	325

___________

(1)See following discussion in the section Acquisition of additional interests in BRMH below.

Dividends and distributions [Table Text Block]

Dividends and distributions

The organizational documents of entities in which we have an equity-method investment generally require distribution of available cash to members on at least a quarterly basis. These transactions reduced the carrying value of our investments and included:

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Appalachia Midstream Investments	$	415	$	433	$	357
Laurel Mountain	112		33		31
Gulfstream	89		90		93
RMM	52		45		39
Blue Racer (1)	49		47		47
Discovery	49		44		21
OPPL	34		26		50
Other	65		39		15
	$	865	$	757	$	653

___________

(1)See previous discussion in the section Acquisition of additional interests in BRMH above.

Summarized Financial Position and Results of Operations of Equity Method Investments [Table Text Block]

Summarized Financial Position and Results of Operations of All Equity-Method Investments

	December 31,
	2022		2021
	(Millions)
Assets (liabilities):
Current assets	$	964	$	743
Noncurrent assets	12,701		13,211
Current liabilities	(632)		(435)
Noncurrent liabilities	(3,789)		(3,774)

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Gross revenue	$	5,520	$	4,688	$	2,625
Operating income	1,268		1,191		508
Net income	1,102		1,006		459

XML

Property, Plant, and Equipment (Tables)

12 Months Ended

Dec. 31, 2022

Property, Plant and Equipment [Abstract]

Property, Plant, and Equipment [Table Text Block]

The following table presents nonregulated and regulated Property, plant, and equipment – net as presented on the Consolidated Balance Sheet for the years ended:

	Estimated Useful Life  (1) (Years)	Depreciation Rates (1) (%)	December 31,
			2022		2021
			(Millions)
Nonregulated:
Natural gas gathering and processing facilities	5 - 40		$	19,163	$	18,203
Construction in progress	Not applicable		997		331
Oil and gas properties	Units of production		874		572
Other	0 - 45		2,998		2,649
Regulated:
Natural gas transmission facilities		1.25 - 7.13	19,521		19,201
Construction in progress	Not applicable	Not applicable	708		475
Other	5 - 45	0.00 - 33.33	2,796		2,753
Total property, plant, and equipment, at cost			47,057		44,184
Accumulated depreciation and amortization			(16,168)		(14,926)
Property, plant, and equipment — net			$	30,889	$	29,258

__________

(1)    Estimated useful life and depreciation rates are presented as of December 31, 2022. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC.

Schedule of Change in Asset Retirement Obligation

The following table presents the significant changes to our ARO, of which $1.827 billion and $1.590 billion are included in Regulatory liabilities, deferred income, and other with the remaining current portion in Accrued and other current liabilities at December 31, 2022 and 2021, respectively.

	Year Ended December 31,
	2022		2021
	(Millions)
Balance at beginning of year	$	1,665	$	1,222
Liabilities incurred (1)	77		336
Liabilities settled	(22)		(25)
Accretion	85		73
Revisions (2)	109		59
Balance at end of year	$	1,914	$	1,665

___________

(1)Includes $307 million of ARO in 2021 related to acquired upstream properties.

(2)Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2022 revisions reflect changes in removal cost estimates and increases in inflation rates, partially offset by increases in discount rates. The 2021 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, and increases in inflation rates.

XML

Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2022

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Finite-Lived Intangible Assets [Table Text Block]

The gross carrying amount and accumulated amortization of intangible assets, included in Intangible assets – net of accumulated amortization in the Consolidated Balance Sheet, at December 31 are as follows:

	2022				2021
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
	(Millions)
Customer relationships	$	10,065	$	(2,801)	$	9,593	$	(2,448)
Transportation and storage capacity contracts	267		(172)		267		(14)
Other intangible assets	6		(2)		6		(2)
	$	10,338	$	(2,975)	$	9,866	$	(2,464)

XML

Accrued and Other Current Liabilities (Tables)

12 Months Ended

Dec. 31, 2022

Accrued Liabilities, Current [Abstract]

Accrued and Other Current Liabilities [Table Text Block]

	December 31,
	2022		2021
	(Millions)
Interest on debt	$	274	$	277
Employee costs	218		214
Regulatory liabilities (Note 1)	201		56
Contract liabilities	141		134
Asset retirement obligations (Note 9)	87		75
Operating lease liabilities (Note 13)	25		23
Other, including accrued loss contingencies	324		256
	$	1,270	$	1,035

XML

Debt and Banking Arrangements (Tables)

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

Schedule of Long-term Debt Instruments [Table Text Block]

Long-Term Debt

	December 31,
	2022		2021
	(Millions)
Transco:
7.08% Debentures due 2026	$	8	$	8
7.25% Debentures due 2026	200		200
7.85% Notes due 2026	1,000		1,000
4% Notes due 2028	400		400
3.25% Notes due 2030	700		700
5.4% Notes due 2041	375		375
4.45% Notes due 2042	400		400
4.6% Notes due 2048	600		600
3.95% Notes due 2050	500		500
Other financing obligation — Atlantic Sunrise	809		830
Other financing obligation — Leidy South	77		72
Other financing obligation — Dalton	252		254
Northwest Pipeline:
7.125% Debentures due 2025	85		85
4% Notes due 2027	500		500
Williams:
3.35% Notes due 2022	—		750
3.6% Notes due 2022	—		1,250
3.7% Notes due 2023	—		850
4.5% Notes due 2023	600		600
4.3% Notes due 2024	1,000		1,000
4.55% Notes due 2024	1,250		1,250
3.9% Notes due 2025	750		750
4% Notes due 2025	750		750
3.75% Notes due 2027	1,450		1,450
3.5% Notes due 2030	1,000		1,000
2.6% Notes due 2031	1,500		1,500
7.5% Debentures due 2031	339		339
7.75% Notes due 2031	252		252
8.75% Notes due 2032	445		445
4.65% Notes due 2032	1,000		—
6.3% Notes due 2040	1,250		1,250
5.8% Notes due 2043	400		400
5.4% Notes due 2044	500		500
5.75% Notes due 2044	650		650
4.9% Notes due 2045	500		500
5.1% Notes due 2045	1,000		1,000
4.85% Notes due 2048	800		800
3.5% Notes due 2051	650		650
5.3% Notes due 2052	750		—
Various — 7.7% to 8.72% Notes due 2022 to 2027	2		2
Unamortized debt issuance costs	(135)		(131)
Net unamortized debt premium (discount)	(55)		(56)
Total long-term debt, including current portion	22,554		23,675
Long-term debt due within one year	(627)		(2,025)
Long-term debt	$	21,927	$	21,650

Schedule of Maturities of Long-term Debt [Table Text Block]

The following table presents aggregate minimum maturities of long-term debt and other financing obligations, excluding net unamortized debt premium (discount) and debt issuance costs, for each of the next five years: 

	December 31, 2022
	(Millions)
2023	$	629
2024	2,281
2025	1,619
2026	1,245
2027	1,993

Schedule of Line of Credit Facilities [Table Text Block]

Credit Facility

	December 31, 2022
	Stated Capacity		Outstanding
	(Millions)
Long-term credit facility (1)	$	3,750	$	—
Letters of credit under certain bilateral bank agreements			30

________________

(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.

XML

Leases (Tables)

12 Months Ended

Dec. 31, 2022

Leases [Abstract]

Lease, Cost [Table Text Block]

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Lease Cost:
Operating lease cost	$	34	$	35	$	37
Variable lease cost	26		15		19
Sublease income	—		(1)		(1)
Total lease cost	$	60	$	49	$	55
Cash paid for operating lease liabilities	$	33	$	35	$	30

	December 31,
	2022		2021
	(Millions)
Other Information:
Right-of-use asset (included in Regulatory assets, deferred charges, and other)	$	162	$	159
Operating lease liabilities:
Current (included in Accrued and other current liabilities)	$	25	$	23
Noncurrent (included in Regulatory liabilities, deferred income, and other)	$	148	$	141
Weighted-average remaining lease term – operating leases (years)	13		13
Weighted-average discount rate – operating leases	4.62%		4.56%

Lessee, Operating Lease, Liability, Maturity [Table Text Block]

At December 31, 2022, the following table represents our operating lease maturities, including renewal provisions that we have assessed as being reasonably certain of exercise, for each of the years ended December 31:

	(Millions)
2023	$	31
2024	26
2025	20
2026	20
2027	19
Thereafter	122
Total future lease payments	238
Less: Amount representing interest	65
Total obligations under operating leases	$	173

XML

Fair Value Measurements, Guarantees, and Concentration of Credit Risk (Tables)

12 Months Ended

Dec. 31, 2022

Fair Value Disclosures [Abstract]

Fair Value Assets and Liabilities Measured On Recurring Basis [Table Text Block]

The following table presents, by level within the fair value hierarchy, certain of our significant financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, accounts payable, and commercial paper approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.

					Fair Value Measurements Using
	Carrying Amount		Fair Value		Quoted Prices In Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(Millions)
Assets (liabilities) at December 31, 2022:
Measured on a recurring basis:
ARO Trust investments	$	230	$	230	$	230	$	—	$	—
Commodity derivative assets (1)	166		166		20		132		14
Commodity derivative liabilities (1)	(810)		(810)		(22)		(718)		(70)
Other financial assets (liabilities) - net	(5)		(5)		—		(5)		—
Additional disclosures:
Long-term debt, including current portion	(22,554)		(21,569)		—		(21,569)		—
Guarantees	(38)		(25)		—		(9)		(16)
Assets (liabilities) at December 31, 2021:
Measured on a recurring basis:
ARO Trust investments	$	260	$	260	$	260	$	—	$	—
Commodity derivative assets (2)	84		84		2		81		1
Commodity derivative liabilities (2)	(488)		(488)		(69)		(403)		(16)
Other financial assets (liabilities) - net	(7)		(7)		—		(7)		—
Additional disclosures:
Long-term debt, including current portion	(23,675)		(27,768)		—		(27,768)		—
Guarantees	(39)		(26)		—		(10)		(16)

(1)Net commodity derivative assets and liabilities exclude $202 million of net cash collateral in Level 1.

(2)Net commodity derivative assets and liabilities exclude $296 million of net cash collateral in Level 1.

Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation

The following table presents a reconciliation of changes in fair value of our net commodity derivatives classified as Level 3 in the fair value hierarchy.

	Year Ended December 31,
	2022		2021
	(Millions)
Balance at beginning of period	$	(15)	$	(2)
Gains (losses) included in our Consolidated Statement of Income	(31)		(62)
Purchases, issuances, and settlements	(5)		13
Acquired derivatives (Note 3)	—		24
Transfers into Level 3	(24)		—
Transfers out of Level 3	19		12
Balance at end of period	$	(56)	$	(15)

Fair Value Measurements, Nonrecurring [Table Text Block]

The following table presents impairments of assets and equity-method investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy, except as specifically noted.

					Impairments
					Year Ended December 31,
	Segment	Date of Measurement	Fair Value		2022		2021		2020
			(Millions)
Impairment of certain assets:
Certain capitalized project costs (1)	Transmission & Gulf of Mexico	June 30, 2021	$	1			$	2
Certain capitalized project costs (1)	Transmission & Gulf of Mexico	December 31, 2020	42						$	170
Certain gathering assets (2)	Northeast G&P	December 31, 2020	5						12
Impairment of certain assets					$	—	$	2	$	182
Impairment of equity-method investments:
RMM (3)	West	December 31, 2020	$	421					$	108
RMM (4)	West	March 31, 2020	557						243
Brazos Permian II (4)	West	March 31, 2020	—						193
BRMH (5)	Northeast G&P	March 31, 2020	191						229
Appalachia Midstream Investments (5)	Northeast G&P	March 31, 2020	2,700						127
Aux Sable (5)	Northeast G&P	March 31, 2020	7						39
Laurel Mountain (5)	Northeast G&P	March 31, 2020	236						10
Discovery (5)	Transmission & Gulf of Mexico	March 31, 2020	367						97
Impairment of equity-method investments					$	—	$	—	$	1,046

______________

(1)Relates to capitalized project development costs for the Northeast Supply Enhancement project. Approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection have been denied and we have not refiled at this time. Beginning in May 2020, we discontinued capitalization of costs related to this project. Considering that the customer precedent agreements and FERC certificate for the project remain in effect, we had previously concluded that the probability of completing the project was sufficient to not require impairment. However, developments in the political and regulatory environments caused us to slightly lower that assessed probability such that the capitalized project costs required impairment. The estimated fair value of the materials within the capitalized project costs at December 31, 2020 considered other internal uses and salvage values for the Property, plant, and equipment – net. The remaining capitalized costs were determined to have no fair value. The estimated fair value of certain capitalized project costs at June 30, 2021, was determined by a market approach, which incorporated an indication of interest by a third-party.

(2)Relates to a gathering system in the Marcellus Shale region, that was sold in 2021. The estimated fair value of the Property, plant, and equipment – net and Intangible assets – net of accumulated amortization was determined using a market approach, which incorporated an indication of interest by a third party. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy.

(3)During the fourth quarter of 2020, RMM renegotiated service contracts with a significant customer in connection with the customer’s Chapter 11 bankruptcy proceedings. The renegotiated contracts result in lower service rates and lower projected future cash flows. As a result, we evaluated this investment for other-than-temporary impairment. The fair value was measured using an income approach. We utilized a discount rate of 18 percent in our analysis.

(4)Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The fair value was measured using an income approach. Both investees operate in primarily oil-driven basins where significant expected reductions in producer activities led to reduced estimates of expected future cash flows. Our fair value estimates also reflected discount rates of approximately 17 percent for these investments. We also considered any debt held at the investee level, and its impact to fair value. The industry weighted-average discount rates utilized were significantly influenced by the market declines previously discussed.

(5)Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The impairments within our Northeast G&P segment are primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices which historically trend with crude oil prices. The fair values of our investments in BRMH and Aux Sable Liquid Products LP (Aux Sable) were estimated using a market approach, reflecting valuation multiples ranging from 5.0x to 6.2x EBITDA (weighted-average 6.0x). The fair values of the other investments, including gathering systems that are part of Appalachia Midstream Investments, were estimated using an income approach, with discount rates ranging from 9.7 percent to 13.5 percent (weighted-average 12.6 percent). We also considered any debt held at the investee level, and its impact to fair value. The assumed valuation multiples and industry weighted-average discount rates utilized were both significantly influenced by the market declines previously discussed.

Concentration of receivables, net of allowances, by product or service [Table Text Block]

The following table summarizes concentration of receivables, net of allowances:

	December 31,
	2022		2021
	(Millions)
NGLs, natural gas, and related products and services	$	505	$	486
Regulated interstate natural gas transportation and storage	311		274
Marketing of natural gas and NGLs	858		609
Upstream activities	97		82
Accounts Receivable related to revenues from contracts with customers	1,771		1,451
Receivables from derivatives	889		462
Other accounts receivable	63		65
Trade accounts and other receivables - net	$	2,723	$	1,978

XML

Derivatives (Tables)

12 Months Ended

Dec. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

At December 31, 2022, the notional volume of the net long (short) positions for our commodity-related derivative contracts were as follows:

	Commodity	Unit of Measure	Net Long (Short) Position
Index Risk	Natural Gas	MMBtu	745,415,032
Central Hub Risk - Henry Hub	Natural Gas	MMBtu	(46,154,200)
Basis Risk	Natural Gas	MMBtu	(50,737,802)
Central Hub Risk - Mont Belvieu	Natural Gas Liquids	Barrels	35,548
Basis Risk	Natural Gas Liquids	Barrels	(3,880,364)
Central Hub Risk - WTI	Crude Oil	Barrels	(123,250)

Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location

The fair value of commodity-related derivatives, which are not designated as hedging instruments for accounting purposes, was reflected as follows:

	December 31, 2022				December 31, 2021
Derivative Category	Assets		(Liabilities)		Assets		(Liabilities)
	(Millions)
Current	$	1,099	$	(1,278)	$	619	$	(760)
Noncurrent	269		(734)		166		(429)
Total derivatives	$	1,368	$	(2,012)	$	785	$	(1,189)
Counterparty and collateral netting offset	(1,034)		1,236		(476)		772
Amounts recognized in our Consolidated Balance Sheet	$	334	$	(776)	$	309	$	(417)

Pretax Effect Of Interest Rate And Energy Related Derivatives

The pre-tax effects of commodity-related derivative instruments in Net gain (loss) on commodity derivatives reflected within Total revenues and Net processing commodity expenses in our Consolidated Statement of Income were as follows:

	Gain (Loss)
	Year Ended December 31,
	2022		2021		2020
	(Millions)
Realized commodity-related derivatives designated as hedging instruments	$	—	$	(55)	$	(2)
Realized commodity-related derivatives not designated as hedging instruments	(91)		16		(3)
Unrealized commodity-related derivatives not designated as hedging instruments	(296)		(109)		—
Net gain (loss) on commodity derivatives	$	(387)	$	(148)	$	(5)
Realized commodity-related derivatives not designated as hedging instruments in Net processing commodity expenses	$	16	$	2	$	1
Unrealized commodity-related derivatives not designated as hedging instruments in Net processing commodity expenses	$	47	$	—	$	—

XML

Segment Disclosures (Tables)

12 Months Ended

Dec. 31, 2022

Segment Reporting [Abstract]

Reconciliation of Modified EBITDA to Net income (loss) [Table Text Block]

The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in our Consolidated Statement of Income:

	Year Ended December 31,
	2022		2021		2020
	(Millions)
Modified EBITDA by segment:
Transmission & Gulf of Mexico	$	2,674	$	2,621	$	2,379
Northeast G&P	1,796		1,712		1,489
West	1,211		961		947
Gas & NGL Marketing Services (1)	(40)		22		51
Other	434		178		(15)
	6,075		5,494		4,851
Accretion expense associated with asset retirement obligations for nonregulated operations	(51)		(45)		(35)
Depreciation and amortization expenses	(2,009)		(1,842)		(1,721)
Impairment of goodwill	—		—		(187)
Equity earnings (losses)	637		608		328
Impairment of equity-method investments	—		—		(1,046)
Other investing income (loss) – net	16		7		8
Proportional Modified EBITDA of equity-method investments	(979)		(970)		(749)
Interest expense	(1,147)		(1,179)		(1,172)
(Provision) benefit for income taxes	(425)		(511)		(79)
Net income (loss)	$	2,117	$	1,562	$	198

____________

(1)    Modified EBITDA for 2022, 2021, and 2020, includes charges of $161 million, $15 million, and $17 million respectively, associated with lower of cost or net realizable value adjustments to our inventory. These charges are reflected in Product Sales or Product costs in our Consolidated Statement of Income (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies). Net unrealized commodity-related derivatives gains of $47 million in 2022 and $0 in 2021 and 2020 are reflected in Net processing commodity expenses.

Reconciliation of revenue from segment to consolidated [Table Text Block]

The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Income and Other financial information:

	Transmission & Gulf of Mexico		Northeast G&P		West		Gas & NGL Marketing Services (1)		Other		Eliminations		Total
	(Millions)
2022
Segment revenues:
Service revenues
External	$	3,461	$	1,613	$	1,443	$	3	$	16	$	—	$	6,536
Internal	118		41		99		—		8		(266)		—
Total service revenues	3,579		1,654		1,542		3		24		(266)		6,536
Total service revenues – commodity consideration	64		14		182		—		—		—		260
Product sales
External	228		28		145		4,052		103		—		4,556
Internal	176		106		696		(518)		603		(1,063)		—
Total product sales	404		134		841		3,534		706		(1,063)		4,556
Net gain (loss) on commodity derivatives
Realized	—		—		(4)		17		(104)		—		(91)
Unrealized	—		—		—		(321)		25		—		(296)
Total net gain (loss) on commodity derivatives (2)	—		—		(4)		(304)		(79)		—		(387)
Total revenues	$	4,047	$	1,802	$	2,561	$	3,233	$	651	$	(1,329)	$	10,965
Other financial information:
Additions to long-lived assets	$	1,420	$	261	$	1,507	$	4	$	406	$	—	$	3,598
Proportional Modified EBITDA of equity-method investments	193		654		132		—		—		—		979
2021
Segment revenues:
Service revenues
External	$	3,310	$	1,490	$	1,178	$	3	$	20	$	—	$	6,001
Internal	75		38		70		—		12		(195)		—
Total service revenues	3,385		1,528		1,248		3		32		(195)		6,001
Total service revenues – commodity consideration	52		7		179		—		—		—		238
Product sales
External	231		13		60		4,094		138		—		4,536
Internal	118		86		583		198		195		(1,180)		—
Total product sales	349		99		643		4,292		333		(1,180)		4,536
Net gain (loss) on commodity derivatives
Realized	—		—		(44)		25		(20)		—		(39)
Unrealized	—		—		—		(109)		—		—		(109)
Total net gain (loss) on commodity derivatives (2)	—		—		(44)		(84)		(20)		—		(148)
Total revenues	$	3,786	$	1,634	$	2,026	$	4,211	$	345	$	(1,375)	$	10,627
Other financial information:
Additions to long-lived assets	$	861	$	164	$	209	$	1	$	620	$	—	$	1,855
Proportional Modified EBITDA of equity-method investments	183		682		105		—		—		—		970

	Transmission & Gulf of Mexico		Northeast G&P		West		Gas & NGL Marketing Services (1)		Other		Eliminations		Total
	(Millions)
2020
Segment revenues:
Service revenues
External	$	3,207	$	1,416	$	1,248	$	32	$	21	$	—	$	5,924
Internal	50		49		24		—		13		(136)		—
Total service revenues	3,257		1,465		1,272		32		34		(136)		5,924
Total service revenues – commodity consideration	21		7		101		—		—		—		129
Product sales
External	144		16		20		1,491		—		—		1,671
Internal	47		41		132		111		—		(331)		—
Total product sales	191		57		152		1,602		—		(331)		1,671
Net gain (loss) on commodity derivatives
Realized	—		—		(2)		(3)		—		—		(5)
Unrealized	—		—		—		—		—		—		—
Total net gain (loss) on commodity derivatives (2)	—		—		(2)		(3)		—		—		(5)
Total revenues	$	3,469	$	1,529	$	1,523	$	1,631	$	34	$	(467)	$	7,719
Other financial information:
Additions to long-lived assets	$	706	$	137	$	318	$	—	$	122	$	—	$	1,283
Proportional Modified EBITDA of equity-method investments	166		473		110		—		—		—		749

______________

(1)    See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.

(2)    We record transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue.

Total assets and equity method investments by reporting segment [Table Text Block]

Segment assets include Investments, Property, plant, and equipment – net, and Intangible assets – net of accumulated amortization. The following table reflects segment assets and equity-method investments by reportable segments:

	Segment Assets				Equity-Method Investments
	December 31, 2022		December 31, 2021		December 31, 2022		December 31, 2021
	(Millions)
Transmission & Gulf of Mexico	$	17,795	$	17,142	$	629	$	602
Northeast G&P	13,539		13,861		3,566		3,681
West	10,710		9,698		843		838
Gas & NGL Marketing Services	130		294		—		—
Other	1,143		792		10		—
Total	43,317		41,787		$	5,048	$	5,121
Total current assets	3,797		4,549
Regulatory assets, deferred charges, and other	1,319		1,276
Total assets	$	48,433	$	47,612

XML

Share Repurchase Program (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Sep. 03, 2021
Equity, Class of Treasury Stock [Line Items]
Stock Repurchase Program, Authorized Amount			$ 1,500
Purchase of treasury stock	$ 9	$ 0

XML

General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Gulfstream Natural Gas System, LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	50.00%
Discovery Producer Services LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	60.00%
Laurel Mountain Midstream, LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	69.00%
Blue Racer Midstream LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	50.00%
Overland Pass Pipeline Company LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	50.00%
Rocky Mountain Midstream Holdings LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	50.00%
Transmission And Gulf Of Mexico [Member] | Gulfstream Natural Gas System, LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	50.00%
Transmission And Gulf Of Mexico [Member] | Discovery Producer Services LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	60.00%
Transmission And Gulf Of Mexico [Member] | Williams Companies Inc [Member] | Gulfstar One [Member]
General and Description Of Business [Abstract]
Variable Interest Entity Ownership Percentage	51.00%
Northeast G And P [Member] | Laurel Mountain Midstream, LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	69.00%
Northeast G And P [Member] | Blue Racer Midstream LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	50.00%	50.00%
Northeast G And P [Member] | Williams Companies Inc [Member] | Northeast JV [Member]
General and Description Of Business [Abstract]
Variable Interest Entity Ownership Percentage	65.00%
Northeast G And P [Member] | Williams Companies Inc [Member] | Cardinal Gas Services LLC [Member]
General and Description Of Business [Abstract]
Variable Interest Entity Ownership Percentage	66.00%
Northeast G And P [Member] | Williams Companies Inc [Member] | Appalachia Midstream Services, LLC [Member]
General and Description Of Business [Abstract]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	66.00%
West [Member] | Overland Pass Pipeline Company LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	50.00%
West [Member] | Rocky Mountain Midstream Holdings LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	50.00%
West [Member] | Targa Train 7 LLC [Member]
General and Description Of Business [Abstract]
Equity Method Investment, Ownership Percentage	20.00%
West [Member] | Williams Companies Inc [Member] | Conway Fractionator [Member]
General and Description Of Business [Abstract]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest	50.00%
West [Member] | Williams Companies Inc [Member] | Brazos Permian II, LLC [Member]
General and Description Of Business [Abstract]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest	15.00%

XML

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets, Current	$ 138	$ 111
Regulatory Assets, Noncurrent	459	415
Total regulated assets	597	526
Regulatory Liabilities, Current	201	56
Regulatory Liabilities, Noncurrent	1,233	1,324
Total regulated liabilities	$ 1,434	1,380
Interest Capitalized [Abstract]
Minimum period of construction for capitalization of interest	3 months
Minimum total project cost for capitalization of interest	$ 1
Retirement Benefits, Description [Abstract]
Threshold For Amortization Of Unrecognized Actuarial Gains Losses	10.00%
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ (24)	(33)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
Retirement Benefits, Description [Abstract]
Accumulated Other Comprehensive Income (Loss), Net of Tax	$ 18	$ 30
Pension Benefits [Member]
Retirement Benefits, Description [Abstract]
Approximate Amortization Period Of Net Actuarial Gain Loss	10 years
Amortization Period Of Difference Between Expected And Actual Return On Plan Assets	5 years
Other Postretirement Benefits [Member]
Retirement Benefits, Description [Abstract]
Approximate Amortization Period Of Net Actuarial Gain Loss	5 years
Minimum [Member]
Leases [Abstract]
Lessee, Operating Lease, Term of Contract	1 year
Minimum [Member] | Pension Benefits [Member]
Retirement Benefits, Description [Abstract]
Threshold For Market Related Value	90.00%
Maximum [Member]
Leases [Abstract]
Lessee, Operating Lease, Term of Contract	20 years
Maximum [Member] | Pension Benefits [Member]
Retirement Benefits, Description [Abstract]
Threshold For Market Related Value	110.00%

XML

Variable Interest Entities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Variable Interest Entity [Line Items]
Assets	$ 48,433	$ 47,612
Equity-method investments	5,048	5,121
Variable Interest Entity, Primary Beneficiary [Member] | Cash and cash equivalents [Member]
Variable Interest Entity [Line Items]
Assets	49	78
Variable Interest Entity, Primary Beneficiary [Member] | Trade accounts and other receivables [Member]
Variable Interest Entity [Line Items]
Assets	136	132
Variable Interest Entity, Primary Beneficiary [Member] | Inventories [Member]
Variable Interest Entity [Line Items]
Assets	4	3
Variable Interest Entity, Primary Beneficiary [Member] | Other current assets and deferred charges [Member]
Variable Interest Entity [Line Items]
Assets	7	7
Variable Interest Entity, Primary Beneficiary [Member] | Property, plant, and equipment, net [Member]
Variable Interest Entity [Line Items]
Assets	5,154	5,295
Variable Interest Entity, Primary Beneficiary [Member] | Intangible assets - net of accumulated amortization [Member]
Variable Interest Entity [Line Items]
Assets	2,158	2,267
Variable Interest Entity, Primary Beneficiary [Member] | Regulatory assets, deferred charges, and other [Member]
Variable Interest Entity [Line Items]
Assets	29	20
Variable Interest Entity, Primary Beneficiary [Member] | Accounts payable [Member]
Variable Interest Entity [Line Items]
Liabilities	(76)	(61)
Variable Interest Entity, Primary Beneficiary [Member] | Accrued and Other Current Liabilities [Member]
Variable Interest Entity [Line Items]
Liabilities	(34)	(29)
Variable Interest Entity, Primary Beneficiary [Member] | Regulatory liabilities, deferred income, and other [Member]
Variable Interest Entity [Line Items]
Liabilities	$ (275)	$ (287)
Variable Interest Entity, Primary Beneficiary [Member] | Williams Companies Inc [Member] | Northeast JV [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Ownership Percentage	65.00%
Variable Interest Entity, Primary Beneficiary [Member] | Williams Companies Inc [Member] | Gulfstar One [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Ownership Percentage	51.00%
Variable Interest Entity, Primary Beneficiary [Member] | Williams Companies Inc [Member] | Cardinal Gas Services LLC [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Ownership Percentage	66.00%
Variable Interest Entity, Not Primary Beneficiary [Member] | Williams Companies Inc [Member] | Targa Train 7 LLC [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Ownership Percentage	20.00%
Equity-method investments	$ 46
Variable Interest Entity, Not Primary Beneficiary [Member] | Williams Companies Inc [Member] | Brazos Permian II, LLC [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity Ownership Percentage	15.00%
Equity-method investments	$ 16

XML

Acquisitions (Details) - USD ($) $ in Millions					6 Months Ended	8 Months Ended	12 Months Ended
		Aug. 31, 2022	Apr. 29, 2022	Jul. 01, 2021	Dec. 31, 2021	Dec. 31, 2022	Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
Business Acquisition [Line Items]
Revenues							$ 10,965		$ 10,627		$ 7,719
Modified EBITDA Earnings Loss							6,075		5,494		4,851
Net income (loss) attributable to The Williams Companies, Inc.							2,049		1,517		211
Payments to Acquire Productive Assets							3,598		1,855		1,283
Pro Forma [Member]
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Revenue							11,010		10,933		7,793
Business Acquisition, Pro Forma Net Income (Loss)							2,067		1,563		198
Product [Member]
Business Acquisition [Line Items]
Revenues							4,556		4,536		1,671
Energy Commodities and Service
Business Acquisition [Line Items]
Revenues	[1]						(387)		(148)		(5)
Gain (Loss) on Derivative Instruments | Energy Related Derivative | Not Designated as Hedging Instrument [Member]
Business Acquisition [Line Items]
Unrealized Gain (Loss) on Derivatives							(296)		(109)		0
West [Member] | Product [Member]
Business Acquisition [Line Items]
Revenues							145		60		20
West [Member] | Energy Commodities and Service
Business Acquisition [Line Items]
Revenues	[1]						(4)		(44)		(2)
West [Member] | Operating Segments [Member]
Business Acquisition [Line Items]
Revenues							2,561		2,026		1,523
Modified EBITDA Earnings Loss							1,211		961		947
Payments to Acquire Productive Assets							1,507		209		318
West [Member] | Operating Segments [Member] | Product [Member]
Business Acquisition [Line Items]
Revenues							841		643		152
Gas & NGL Marketing Services | Product [Member]
Business Acquisition [Line Items]
Revenues							4,052	[2]	4,094		1,491
Gas & NGL Marketing Services | Energy Commodities and Service
Business Acquisition [Line Items]
Revenues	[1]						(304)		(84)		(3)
Gas & NGL Marketing Services | Operating Segments [Member]
Business Acquisition [Line Items]
Revenues							3,233	[2]	4,211		1,631
Modified EBITDA Earnings Loss	[3]						(40)		22		51
Payments to Acquire Productive Assets							4		1		0
Gas & NGL Marketing Services | Operating Segments [Member] | Product [Member]
Business Acquisition [Line Items]
Revenues							3,534	[2]	4,292		1,602
Transmission And Gulf Of Mexico [Member] | NorTex Acquisition
Business Acquisition [Line Items]
Payments to Acquire Productive Assets		$ 424
Transmission And Gulf Of Mexico [Member] | Product [Member]
Business Acquisition [Line Items]
Revenues							228		231		144
Transmission And Gulf Of Mexico [Member] | Energy Commodities and Service
Business Acquisition [Line Items]
Revenues	[1]						0		0		0
Transmission And Gulf Of Mexico [Member] | Operating Segments [Member]
Business Acquisition [Line Items]
Revenues							4,047		3,786		3,469
Modified EBITDA Earnings Loss							2,674		2,621		2,379
Payments to Acquire Productive Assets							1,420		861		706
Transmission And Gulf Of Mexico [Member] | Operating Segments [Member] | Product [Member]
Business Acquisition [Line Items]
Revenues							404		349		191
Trace Midstream Acquisition
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired			100.00%
Business Combination, Consideration Transferred			$ 972
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents			39
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables			18
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment			448
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles			472
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets			20
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets			997
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable			12
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other			5
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other			8
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities			25
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net			$ 972
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life			20 years
Percentage Of Finite Lived Intangible Assets Impacted By Our Intent Or Ability To Renew Or Extend Arrangement			2.00%
Acquired Finite-lived Intangible Asset, Weighted-Average Period before Renewal or Extension			19 years
Trace Midstream Acquisition | Pro Forma [Member]
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Revenue							45	[4]	118
Business Acquisition, Pro Forma Net Income (Loss)							$ 18	[4]	42
Trace Midstream Acquisition | West [Member] | Selling, general and administrative expenses [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs						$ 8
Trace Midstream Acquisition | West [Member] | Operating Segments [Member]
Business Acquisition [Line Items]
Revenues						148
Modified EBITDA Earnings Loss						$ 73
Sequent Acquisition
Business Acquisition [Line Items]
Business Combination, Consideration Transferred				$ 159
Business Combination Working Capital Acquired				109
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents				8
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables				498
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory				121
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other				4
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment				5
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles				306
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets				3
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets				1,051
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable				514
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other				46
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other				1
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities				892
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net				$ 159
Sequent Acquisition | Pro Forma [Member]
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Revenue									188	[5]	74
Business Acquisition, Pro Forma Net Income (Loss)									$ 4	[5]	$ (13)
Sequent Acquisition | Minimum [Member]
Business Acquisition [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life				1 year
Sequent Acquisition | Maximum [Member]
Business Acquisition [Line Items]
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life				8 years
Sequent Acquisition | Derivative
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other				$ 57
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets				49
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other				116
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other				$ 215
Sequent Acquisition | Gas & NGL Marketing Services
Business Acquisition [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				100.00%
Sequent Acquisition | Gas & NGL Marketing Services | Energy Commodities and Service
Business Acquisition [Line Items]
Revenues					$ (43)
Sequent Acquisition | Gas & NGL Marketing Services | Selling, general and administrative expenses [Member]
Business Acquisition [Line Items]
Business Combination, Acquisition Related Costs					5
Sequent Acquisition | Gas & NGL Marketing Services | Gain (Loss) on Derivative Instruments | Energy Related Derivative | Not Designated as Hedging Instrument [Member]
Business Acquisition [Line Items]
Unrealized Gain (Loss) on Derivatives					(109)
Sequent Acquisition | Gas & NGL Marketing Services | Operating Segments [Member]
Business Acquisition [Line Items]
Modified EBITDA Earnings Loss					(112)
Sequent Acquisition | Gas & NGL Marketing Services | Operating Segments [Member] | Product [Member]
Business Acquisition [Line Items]
Revenues					(43)
Affiliate Costs					$ 80

[1] We record transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue.

[2] See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.

[3] Modified EBITDA for 2022, 2021, and 2020, includes charges of $161 million, $15 million, and $17 million respectively, associated with lower of cost or net realizable value adjustments to our inventory. These charges are reflected in Product Sales or Product costs in our Consolidated Statement of Income (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies). Net unrealized commodity-related derivatives gains of $47 million in 2022 and $0 in 2021 and 2020 are reflected in Net processing commodity expenses.

[4] Excludes results from operations acquired in the Trace Acquisition for the period beginning on the acquisition date of April 29, 2022, as these results are included in the amounts as reported.

[5] Excludes results from operations acquired in the Sequent Acquisition for the period beginning on the acquisition date of July 1, 2021, as these results are included in the amounts as reported.

XML

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Director
Related Party Transaction [Line Items]
Revenue from Related Parties	$ 180
Related Party Costs	86
Equity Method Investee [Member]
Related Party Transaction [Line Items]
Accounts Payable, Related Parties, Current	87	$ 89
OperatingFeesAndCostsBilledToThirdParty	65	70	$ 79
Accounts Receivable, Related Parties, Current	17	9
Related Party Transaction, Expenses from Transactions with Related Party	1,346	948	348
Related Party Transaction, Other Revenues from Transactions with Related Party	$ 76	$ 46	$ 26

XML

Revenue by Category (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		$ 17,773	$ 12,784	$ 7,653
Revenue Not from Contract with Customer	[1]	7,935	2,644	66
Revenue Not from Contract with Customer, Other	[2]	(14,743)	(4,801)
Total revenues		10,965	10,627	7,719
Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3,067	2,955	2,846
NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3,072	2,706	2,756
NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		260	238	129
Total revenues		260	238	129
Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		308	264	253
Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		6,707	6,163	5,984
Total revenues		6,536	6,001	5,924
Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		11,066	6,621	1,669
Total revenues		4,556	4,536	1,671
Transco [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,885	2,645	2,494
Revenue Not from Contract with Customer	[1]	24	10	10
Revenue Not from Contract with Customer, Other	[2]	0	0
Total revenues		2,909	2,655	2,504
Transco [Member] | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,696	2,547	2,404
Transco [Member] | NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Transco [Member] | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Transco [Member] | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		10	10	10
Transco [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,706	2,557	2,414
Transco [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		179	88	80
Northwest Pipeline [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		443	441	449
Revenue Not from Contract with Customer	[1]	4	3	0
Revenue Not from Contract with Customer, Other	[2]	0	0
Total revenues		447	444	449
Northwest Pipeline [Member] | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		443	441	449
Northwest Pipeline [Member] | NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Northwest Pipeline [Member] | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Northwest Pipeline [Member] | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Northwest Pipeline [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		443	441	449
Northwest Pipeline [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Gulf of Mexico Midstream and Storage [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		707	687	510
Revenue Not from Contract with Customer	[1]	10	8	9
Revenue Not from Contract with Customer, Other	[2]	0	0
Total revenues		717	695	519
Gulf of Mexico Midstream and Storage [Member] | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Gulf of Mexico Midstream and Storage [Member] | NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		365	344	348
Gulf of Mexico Midstream and Storage [Member] | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		64	52	21
Gulf of Mexico Midstream and Storage [Member] | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		27	22	27
Gulf of Mexico Midstream and Storage [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		456	418	396
Gulf of Mexico Midstream and Storage [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		251	269	114
Northeast Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,776	1,609	1,507
Revenue Not from Contract with Customer	[1]	26	25	22
Revenue Not from Contract with Customer, Other	[2]	0	0
Total revenues		1,802	1,634	1,529
Northeast Midstream [Member] | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Northeast Midstream [Member] | NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,395	1,308	1,279
Northeast Midstream [Member] | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		14	7	7
Northeast Midstream [Member] | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		233	195	164
Northeast Midstream [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,642	1,510	1,450
Northeast Midstream [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		134	99	57
West Midstream [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,553	2,058	1,514
Revenue Not from Contract with Customer	[1]	8	(32)	9
Revenue Not from Contract with Customer, Other	[2]	0	0
Total revenues		2,561	2,026	1,523
West Midstream [Member] | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
West Midstream [Member] | NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,476	1,184	1,226
West Midstream [Member] | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		182	179	101
West Midstream [Member] | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		54	52	35
West Midstream [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		1,712	1,415	1,362
West Midstream [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		841	643	152
Gas & NGL Marketing Services
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		10,771	6,407	1,634
Revenue Not from Contract with Customer	[1]	7,929	2,632	(3)
Revenue Not from Contract with Customer, Other	[2]	(15,467)	(4,828)
Total revenues		3,233	4,211	1,631
Gas & NGL Marketing Services | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Gas & NGL Marketing Services | NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Gas & NGL Marketing Services | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Gas & NGL Marketing Services | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3	3	32
Gas & NGL Marketing Services | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3	3	32
Gas & NGL Marketing Services | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		10,768	6,404	1,602
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		706	334	1
Revenue Not from Contract with Customer	[1]	(55)	11	33
Revenue Not from Contract with Customer, Other	[2]	0	0
Total revenues		651	345	34
Other [Member] | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Other [Member] | NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Other [Member] | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Other [Member] | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	1	1
Other [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	1	1
Other [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		706	333	0
Intersegment Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(2,068)	(1,397)	(456)
Revenue Not from Contract with Customer	[1]	(11)	(13)	(14)
Revenue Not from Contract with Customer, Other	[2]	724	27
Total revenues		(1,355)	(1,383)	(470)
Intersegment Eliminations [Member] | Regulated Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(72)	(33)	(7)
Intersegment Eliminations [Member] | NonRegulated Service Monetary Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(164)	(130)	(97)
Intersegment Eliminations [Member] | NonRegulated Service Commodity Consideration [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0	0	0
Intersegment Eliminations [Member] | Other Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(19)	(19)	(16)
Intersegment Eliminations [Member] | Service [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(255)	(182)	(120)
Intersegment Eliminations [Member] | Product [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		$ (1,813)	$ (1,215)	$ (336)

[1] Revenues not derived from contracts with customers primarily consist of physical product sales related to derivative contracts, realized and unrealized gains and losses associated with our derivative contracts, which are reported in Net gain (loss) on commodity derivatives in the Consolidated Statement of Income, management fees that we receive for certain services we provide to operated equity-method investments, and leasing revenues associated with our headquarters building.

[2] Other adjustments reflect certain costs of Gas & NGL Marketing Services’ risk management activities. As we are acting as agent for natural gas marketing customers or engage in energy trading activities, the resulting revenues are presented net of the related costs of those activities in the Consolidated Statement of Income (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies).

XML

Revenue Recognition Contract Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Contract With Customer, Asset [Line Items]
Contract with Customer, Asset, Net - Beginning of Period	$ 22	$ 12
Contract with Customer, Asset, Cumulative Catch-up Adjustment to Revenue, Change in Measure of Progress	208	184
Contract with Customer, Asset, Reclassified to Receivable	(201)	(174)
Contract with Customer, Asset, Net - End of Period	$ 29	$ 22

XML

Revenue Recognition Contract Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Contract With Customer, Liability [Line Items]
Contract with Customer, Liability - Beginning of Period	$ 1,126	$ 1,209
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Change in Measure of Progress	180	116
Other Significant Noncash Transaction, Value of Consideration Received	9	10
Contract with Customer, Liability, Increase (Decrease) for Contract Acquired in Business Combination	2	1
Contract with Customer, Liability, Revenue Recognized	(274)	(210)
Contract with Customer, Liability - End of Period	$ 1,043	$ 1,126

XML

Revenue Recognition Contract Liabilities Performance Obligations (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	$ 1,043	$ 1,126	$ 1,209
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	142
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	122
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	117
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	112
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	101
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Contract with Customer, Liability	$ 449
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Performance Obligations Related To Contract Liabilities [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period

XML

Revenue Recognition Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2022 USD ($)
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	$ 29,790
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	3,643
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	3,388
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	3,149
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	2,520
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	2,415
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue Recognition [Abstract]
Revenue, Remaining Performance Obligation, Amount	$ 14,675
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Remaining Performance Obligations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period

XML

Provision (Benefit) for Income Taxes Tax Provison (Benefit) Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Current :
Federal	$ (25)	$ (1)	$ (29)
State	19	3	0
Total	(6)	2	(29)
Deferred:
Federal	424	421	98
State	7	88	10
Total	431	509	108
Less: Provision (benefit) for income taxes	$ 425	$ 511	$ 79

XML

Provision (Benefit) for Income Taxes Reconciliations to Recorded Tax Provision (Benefit) Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Effective Income Tax Rate Reconciliation [Abstract]
Provision (benefit) at statutory rate	$ 534	$ 435	$ 58
Increases (decreases) in taxes resulting from:
State income taxes (net of federal benefit)	113	71	6
State deferred income tax rate change	(92)	0	0
Federal valuation allowance	(70)	3	1
Federal settlements	(45)	0	0
Impact of nontaxable noncontrolling interests	(14)	(9)	3
Other – net	(1)	11	11
Less: Provision (benefit) for income taxes	$ 425	$ 511	$ 79

XML

Provision (Benefit) for Income Taxes Deferred Tax Table (Details) - USD ($) $ in Millions	Dec. 31, 2022	Jun. 30, 2022	Dec. 31, 2021
Gross deferred income tax liabilities:
Property, plant and equipment	$ 3,171		$ 2,777
Investments	1,784		1,669
Other	138		154
Total gross deferred income tax liabilities	5,093		4,600
Gross deferred income tax assets:
Accrued liabilities	1,108		872
Foreign tax credits	91	$ 70	140
Federal loss carryovers	730		879
State losses and credits	356		421
Other	121		132
Total gross deferred income tax assets	2,406		2,444
Less valuation allowance	200		297
Net deferred income tax assets	2,206		2,147
Deferred income tax liabilities	$ 2,887		$ 2,453

XML

Provision (Benefit) for Income Taxes Textuals (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Jun. 30, 2022
Income Tax Contingency [Line Items]
Foreign income (loss) in Income from continuing operations before income taxes		$ (2)	$ (1)
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount	$ 113	71	6
Deferred Tax Assets, Charitable Contribution Carryforwards	25
Deferred Tax Assets, Tax Credit Carryforwards	705
Income Taxes Paid	13
Proceeds from Income Tax Refunds		45	40
Deferred Tax Assets, Tax Credit Carryforwards, Foreign	91	140		$ 70
Tax Adjustments, Settlements, and Unusual Provisions	45
Total interest and penalties recognized as part of income tax provision	(3)	(1)	$ (1)
Total interest and penalties accrued as uncertain tax positions	0	$ 4
Settlement with Taxing Authority
Income Tax Contingency [Line Items]
Proceeds from Income Tax Refunds	7
Less Than
Income Tax Contingency [Line Items]
Foreign income (loss) in Income from continuing operations before income taxes	$ 1

XML

EBPs Funded Status (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Defined Contribution Plan
Percentage of eligible compensation the employer will match of employee contributions		6.00%
Employer's contributions charged to expense under defined contribution plan		$ 53	$ 45	$ 42
Pension Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year		1,133	1,183
Service cost		28	30	31
Interest cost		31	28	36
Plan participants’ contributions		0	0
Benefits paid		(78)	(83)
Net actuarial loss (gain) (1)	[1]	(162)	(21)
Settlements		(12)	(4)
Net increase (decrease) in benefit obligation		(193)	(50)
Benefit obligation at end of year		940	1,133	1,183
Other Postretirement Benefits [Member]
Change in benefit obligation:
Benefit obligation at beginning of year		200	220
Service cost		1	1	1
Interest cost		6	5	7
Plan participants’ contributions		2	2
Benefits paid		(12)	(14)
Net actuarial loss (gain) (1)	[1]	(45)	(14)
Settlements		0	0
Net increase (decrease) in benefit obligation		(48)	(20)
Benefit obligation at end of year		$ 152	$ 200	$ 220

[1] 2022 amounts are due primarily to the following factors: Pension benefits - discount rate assumptions, partially offset by change in interest crediting rate assumption; Other Postretirement Benefits - discount rate assumption. 2021 amounts are due primarily to the following factors: Pension Benefits - discount rate assumptions, partially offset by experience-related items; Other Postretirement Benefits - discount rate assumption and experience-related items.

XML

EBP Asset rollforward and B.S. classification (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Amounts included in regulatory liabilities associated with Transco and Northwest Pipeline:
Net regulatory liabilities	$ 130	$ 150
Pension Benefits [Member]
Change in plan assets:
Fair value of plan assets at beginning of year	1,336	1,357
Actual return on plan assets	(132)	62
Employer contributions	3	4
Plan participants’ contributions	0	0
Benefits paid	(78)	(83)
Settlements	(12)	(4)
Net increase (decrease) in fair value of plan assets	(219)	(21)
Fair value of plan assets at end of year	1,117	1,336
Funded status — overfunded (underfunded)	177	203
Amounts recognized in the Consolidated Balance Sheet:
Noncurrent assets	201	229
Current liabilities	(2)	(3)
Noncurrent liabilities	(22)	(23)
Funded status - overfunded (underfunded)	177	203
Accumulated benefit obligation	930	1,118
Plans with a projected benefit obligation in excess of plan assets:
Projected benefit obligation	24	26
Plans with an accumulated benefit obligation in excess of plan assets:
Accumulated benefit obligation	22	22
Fair value of plan assets	0	0
Amounts recognized in Accumulated other comprehensive income (loss):
Net actuarial gain (loss)	(45)	(46)
Other Postretirement Benefits [Member]
Change in plan assets:
Fair value of plan assets at beginning of year	287	278
Actual return on plan assets	(27)	16
Employer contributions	3	5
Plan participants’ contributions	2	2
Benefits paid	(12)	(14)
Settlements	0	0
Net increase (decrease) in fair value of plan assets	(34)	9
Fair value of plan assets at end of year	253	287
Funded status — overfunded (underfunded)	101	87
Amounts recognized in the Consolidated Balance Sheet:
Noncurrent assets	105	91
Current liabilities	(4)	(4)
Noncurrent liabilities	0	0
Funded status - overfunded (underfunded)	101	87
Amounts recognized in Accumulated other comprehensive income (loss):
Net actuarial gain (loss)	$ 18	$ 4

XML

EBP Net Periodic Benefit Cost & OCI (Details 2) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits [Member]
Components of net periodic benefit cost (credit):
Service cost		$ 28	$ 30	$ 31
Interest cost		31	28	36
Expected return on plan assets		(44)	(43)	(53)
Amortization of net actuarial loss		12	14	21
Net actuarial loss from settlements		3	1	9
Reclassification to regulatory liability		0	0	0
Net periodic benefit cost (credit) (1)	[1]	30	30	44
Items Recognized in Other Comprehensive Income (Loss)
Net actuarial gain (loss) arising during the year		(14)	40	112
Amortization of net actuarial loss		12	14	21
Net actuarial loss from settlements		3	1	9
Total recognized in Other comprehensive income (loss)		1	55	142
Other Postretirement Benefits [Member]
Components of net periodic benefit cost (credit):
Service cost		1	1	1
Interest cost		6	5	7
Expected return on plan assets		(10)	(10)	(11)
Amortization of net actuarial loss		0	0	0
Net actuarial loss from settlements		0	0	0
Reclassification to regulatory liability		1	2	2
Net periodic benefit cost (credit) (1)	[1]	(2)	(2)	(1)
Items Recognized in Other Comprehensive Income (Loss)
Net actuarial gain (loss) arising during the year		14	29	(4)
Amortization of net actuarial loss		0	0	0
Net actuarial loss from settlements		0	0	0
Total recognized in Other comprehensive income (loss)		$ 14	$ 29	$ (4)

[1] Components other than Service cost are included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Income.

XML

EBP Key Assumptions (Details 3)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits [Member]
Weighted average assumptions utilized to determine benefit obligations
Discount rate	5.16%	2.82%	2.45%
Rate of compensation increase	3.58%	3.67%	3.76%
Cash balance interest crediting rate	3.50%	3.00%	3.00%
Weighted average assumptions utilized to determine net periodic benefit cost (credit)
Discount rate	2.84%	2.45%	3.08%
Expected long-term rate of return on plan assets	3.81%	3.69%	4.67%
Rate of compensation increase	3.67%	3.76%	3.68%
Cash balance interest crediting rate	3.00%	3.00%	3.50%
Other Postretirement Benefits [Member]
Weighted average assumptions utilized to determine benefit obligations
Discount rate	5.20%	2.93%	2.59%
Weighted average assumptions utilized to determine net periodic benefit cost (credit)
Discount rate	2.93%	2.59%	3.27%
Expected long-term rate of return on plan assets	3.67%	3.61%	4.39%
Health care cost trend rate assumed for next fiscal year	6.80%
Direction and pattern of change for assumed health care cost trend rate	decreases
Ultimate health care cost trend rate	4.50%
Year that rate reaches ultimate trend rate	2032

XML

EBP Plan Assets (Details 4) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Redemption notification period restrictions for commingled investment funds		15 days
Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Redemption notification period restrictions for commingled investment funds		1 day
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		$ 1,117	$ 1,336	$ 1,357
Pension Benefits [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	104	175
Pension Benefits [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	306	399
Pension Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		$ 410	574
Pension Benefits [Member] | Fixed income securities
Defined Benefit Plan Disclosure [Line Items]
Plan asset target allocation		75.00%
Pension Benefits [Member] | Cash management funds | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	$ 45	37
Pension Benefits [Member] | Cash management funds | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	0	0
Pension Benefits [Member] | Cash management funds | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		$ 45	37
Pension Benefits [Member] | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Plan asset target allocation		25.00%
Pension Benefits [Member] | Equity securities | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]		42
Pension Benefits [Member] | Equity securities | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]		19
Pension Benefits [Member] | Equity securities | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value			61
Pension Benefits [Member] | Government debt securities | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	$ 58	99
Pension Benefits [Member] | Government debt securities | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	18	28
Pension Benefits [Member] | Government debt securities | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		76	127
Pension Benefits [Member] | Corporate debt securities | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	0	0
Pension Benefits [Member] | Corporate debt securities | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	284	350
Pension Benefits [Member] | Corporate debt securities | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		284	350
Pension Benefits [Member] | Mutual fund - Municipal bonds | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]		0
Pension Benefits [Member] | Mutual fund - Municipal bonds | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]		0
Pension Benefits [Member] | Mutual fund - Municipal bonds | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value			0
Pension Benefits [Member] | Other | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	1	(3)
Pension Benefits [Member] | Other | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	4	2
Pension Benefits [Member] | Other | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		5	(1)
Pension Benefits [Member] | Commingled investment funds - equities | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[3]	273	288
Pension Benefits [Member] | Commingled investment funds - fixed income | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[3]	434	474
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		253	287	$ 278
Other Postretirement Benefits [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	113	124
Other Postretirement Benefits [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	42	61
Other Postretirement Benefits [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		155	185
Other Postretirement Benefits [Member] | Cash management funds | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	105	14
Other Postretirement Benefits [Member] | Cash management funds | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	0	0
Other Postretirement Benefits [Member] | Cash management funds | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		105	14
Other Postretirement Benefits [Member] | Equity securities | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]		39
Other Postretirement Benefits [Member] | Equity securities | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]		10
Other Postretirement Benefits [Member] | Equity securities | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value			49
Other Postretirement Benefits [Member] | Government debt securities | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	8	13
Other Postretirement Benefits [Member] | Government debt securities | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	3	4
Other Postretirement Benefits [Member] | Government debt securities | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		11	17
Other Postretirement Benefits [Member] | Corporate debt securities | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	0	0
Other Postretirement Benefits [Member] | Corporate debt securities | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	39	47
Other Postretirement Benefits [Member] | Corporate debt securities | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		39	47
Other Postretirement Benefits [Member] | Mutual fund - Municipal bonds | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]		59
Other Postretirement Benefits [Member] | Mutual fund - Municipal bonds | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]		0
Other Postretirement Benefits [Member] | Mutual fund - Municipal bonds | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value			59
Other Postretirement Benefits [Member] | Other | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[1]	0	(1)
Other Postretirement Benefits [Member] | Other | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[2]	0	0
Other Postretirement Benefits [Member] | Other | Fair Value, Inputs, Level 1, 2 and 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value		0	(1)
Other Postretirement Benefits [Member] | Commingled investment funds - equities | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[3]	38	39
Other Postretirement Benefits [Member] | Commingled investment funds - fixed income | Fair Value Measured at Net Asset Value Per Share [Member]
Defined Benefit Plan Disclosure [Line Items]
Total assets at fair value	[3]	$ 60	$ 63

[1] Level 1 includes assets with fair values based on quoted prices in active markets for identical assets. Cash management funds, equity securities traded on U.S. exchanges, U.S. Treasury securities, and mutual funds are included in this level.

[2] Level 2 includes assets with fair values determined by using significant other observable inputs. This level includes equity securities traded on active foreign exchanges and fixed income securities, other than U.S. Treasury securities, that are valued primarily using pricing models which incorporate observable inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads.

[3] The commingled investment funds are measured at fair value using net asset value per share. Certain standard withdrawal restrictions generally apply, which may include redemption notification period restrictions ranging from 1 day to 15 days.

XML

EBP Benefit Pymts & Employer Contributions (Details 5) $ in Millions	Dec. 31, 2022 USD ($)
Pension Benefits [Member]
Expected benefit payments
2023	$ 84
2024	83
2025	84
2026	81
2027	80
2028-2032	389
Expected total plans contribution, approximate	1
Other Postretirement Benefits [Member]
Expected benefit payments
2023	13
2024	13
2025	12
2026	12
2027	11
2028-2032	52
Expected total plans contribution, approximate	$ 4

XML

Investing Activities (Details) - USD ($) $ in Millions				12 Months Ended
		Nov. 18, 2020	Dec. 31, 2019	Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
Schedule of Investments [Line Items]
Income (Loss) from Equity Method Investments				$ (637)		$ (608)		$ (328)
Impairment of equity-method investments				0		0		1,046
Other investing income (loss) - net				16		7		8
Equity-method investment, payments to purchase or contributions				166		115		325
Equity-method investments				5,048		5,121
Other Investments and Securities, at Cost				17		6
Investments				5,065		5,127
Equity-method investment, difference between carrying amount and underlying equity				1,100		1,200
Distributions from equity-method investees (Note 8)				865		757		653
Current assets				3,797		4,549
Current liabilities				(4,890)		(4,972)
Revenues				10,965		10,627		7,719
Operating income				1,268		1,191		508
Net income				2,117		1,562		198
Equity Method Investee [Member]
Schedule of Investments [Line Items]
Accounts Payable, Related Parties, Current				87		89
OperatingFeesAndCostsBilledToThirdParty				65		70		79
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member]
Schedule of Investments [Line Items]
Current assets				964		743
Noncurrent assets				12,701		13,211
Current liabilities				(632)		(435)
Noncurrent liabilities				(3,789)		(3,774)
Revenues				5,520		4,688		2,625
Net income				$ 1,102		1,006		459
Appalachia Midstream Investments [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				66.00%
Income (Loss) from Equity Method Investments								26
Equity-method investment, payments to purchase or contributions				$ 83		84		116
Equity-method investments	[1]			2,975		3,056
Equity-method investment, difference between carrying amount and underlying equity				1,100		1,200
Distributions from equity-method investees (Note 8)				$ 415		433		357
Rocky Mountain Midstream Holdings LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%
Income (Loss) from Equity Method Investments								78
Equity-method investments				$ 395		401
Distributions from equity-method investees (Note 8)				$ 52		45		39
Discovery Producer Services LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				60.00%
Equity-method investment, payments to purchase or contributions				$ 41		0		0
Equity-method investments				345		328
Distributions from equity-method investees (Note 8)				$ 49		44		21
Blue Racer Midstream Holdings LLC
Schedule of Investments [Line Items]
Equity-method investment, payments to purchase or contributions	[2]							157
Distributions from equity-method investees (Note 8)	[3]							47
Overland Pass Pipeline Company LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%
Equity-method investments				$ 386		388
Distributions from equity-method investees (Note 8)				$ 34		26		50
Laurel Mountain Midstream, LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				69.00%
Income (Loss) from Equity Method Investments								11
Equity-method investments				$ 205		226
Distributions from equity-method investees (Note 8)				$ 112		33		31
Gulfstream Natural Gas System, LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%
Equity-method investment, payments to purchase or contributions				$ 14		26		3
Equity-method investments				220		215
Distributions from equity-method investees (Note 8)				89		90		93
Other [Member]
Schedule of Investments [Line Items]
Equity-method investment, payments to purchase or contributions				12		2		49
Equity-method investments				139		130
Distributions from equity-method investees (Note 8)				65		39		15
Total Equity Method Investment [Member]
Schedule of Investments [Line Items]
Distributions from equity-method investees (Note 8)				$ 865		757		653
Blue Racer Midstream LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%
Income (Loss) from Equity Method Investments								10
Equity-method investment, payments to purchase or contributions		$ 157		$ 0	[2]	3	[2]
Equity-method investments				383		377
Distributions from equity-method investees (Note 8)	[3]			49		47
Cardinal Pipeline Company, LLC
Schedule of Investments [Line Items]
Equity-method investment, payments to purchase or contributions				$ 16		$ 0		$ 0
Northeast G And P [Member] | Blue Racer Midstream Holdings LLC
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage			58.00%
Northeast G And P [Member] | Laurel Mountain Midstream, LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				69.00%
Northeast G And P [Member] | Blue Racer Midstream LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%		50.00%
West [Member] | Rocky Mountain Midstream Holdings LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%
West [Member] | Overland Pass Pipeline Company LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				50.00%
West [Member] | Targa Train 7 LLC [Member]
Schedule of Investments [Line Items]
Equity Method Investment, Ownership Percentage				20.00%
Caiman Energy II Acquisition [Member] | Blue Racer Midstream Holdings LLC
Schedule of Investments [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		41.00%
Blue Racer Midstream Holdings LLC | Blue Racer Midstream LLC [Member]
Schedule of Investments [Line Items]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest			50.00%
Beneficial Owner [Member] | Williams Companies Inc [Member] | Blue Racer Midstream LLC [Member]
Schedule of Investments [Line Items]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest			29.00%

[1] Includes equity-method investments in multiple gathering systems in the Marcellus Shale region with an approximate average 66 percent interest.

[2] See following discussion in the section Acquisition of additional interests in BRMH below.

[3] See previous discussion in the section Acquisition of additional interests in BRMH above.

XML

Property, Plant, and Equipment (Details PPE) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, Plant, and Equipment
Property, plant, and equipment, at cost		$ 47,057	$ 44,184
Accumulated depreciation and amortization		(16,168)	(14,926)
Property, plant, and equipment - net		30,889	29,258
Depreciation and amortization expenses		1,498	1,496	$ 1,393
Nonregulated [Member] | Natural gas gathering and processing facilities [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		19,163	18,203
Nonregulated [Member] | Construction in Progress [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		997	331
Nonregulated [Member] | Oil and Gas Properties
Property, Plant, and Equipment
Property, plant, and equipment, at cost		874	572
Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		2,998	2,649
Regulated [Member] | Natural gas transmission facilities [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		19,521	19,201
Regulated [Member] | Construction in Progress [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		708	475
Regulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, plant, and equipment, at cost		2,796	2,753
Regulated [Member] | Acquisition Adjustment Of Regulated Facilities [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Plant Acquisition Adjustments for Intangible Utility Plants		$ 428	$ 468
Period of straight-line amortization		40 years
Minimum [Member] | Nonregulated [Member] | Natural gas gathering and processing facilities [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[1]	5 years
Minimum [Member] | Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[1]	0 years
Minimum [Member] | Regulated [Member] | Natural gas transmission facilities [Member]
Property, Plant, and Equipment
Property, Plant, and Equipment, Depreciation Rate	[1]	1.25%
Minimum [Member] | Regulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[1]	5 years
Property, Plant, and Equipment, Depreciation Rate	[1]	0.00%
Maximum [Member] | Nonregulated [Member] | Natural gas gathering and processing facilities [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[1]	40 years
Maximum [Member] | Nonregulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[1]	45 years
Maximum [Member] | Regulated [Member] | Natural gas transmission facilities [Member]
Property, Plant, and Equipment
Property, Plant, and Equipment, Depreciation Rate	[1]	7.13%
Maximum [Member] | Regulated [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant, and Equipment
Property, Plant and Equipment, Useful Life	[1]	45 years
Property, Plant, and Equipment, Depreciation Rate	[1]	33.33%

[1] (1)    Estimated useful life and depreciation rates are presented as of December 31, 2022. Depreciation rates and estimated useful lives for regulated assets are prescribed by the FERC.

XML

Property, Plant, and Equipment (Details ARO) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligations
Asset Retirement Obligations, Noncurrent		$ 1,827	$ 1,590
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year		1,665	1,222
Liabilities incurred (1)	[1]	77	336
Liabilities settled		(22)	(25)
Accretion		85	73
Revisions (2)	[2]	109	59
Balance at end of year		1,914	1,665
Unusual or Infrequent Item [Line Items]
Asset Retirement Obligation, Liabilities Incurred	[1]	77	336
Upstream Equipment
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Liabilities incurred (1)			307
Unusual or Infrequent Item [Line Items]
Asset Retirement Obligation, Liabilities Incurred			$ 307
Asset Retirement Obligation Costs [Member]
Unusual or Infrequent Item [Line Items]
Transco's annual funding commitment for ARO		$ 16

[1] Includes $307 million of ARO in 2021 related to acquired upstream properties.

[2] Several factors are considered in the annual review process, including inflation rates, current estimates for removal cost, market risk premiums, discount rates, and the estimated remaining useful life of the assets. The 2022 revisions reflect changes in removal cost estimates and increases in inflation rates, partially offset by increases in discount rates. The 2021 revisions reflect changes in removal cost estimates, increases in the estimated remaining useful life of certain assets, and increases in inflation rates.

XML

Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	$ 10,338	$ 9,866
Finite-Lived Intangible Assets, Accumulated Amortization	(2,975)	(2,464)
Customer relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	10,065	9,593
Finite-Lived Intangible Assets, Accumulated Amortization	$ (2,801)	(2,448)
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life	30 years
Amortization of Intangible Assets	$ 353	332	$ 328
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	357
Finite-Lived Intangible Assets, Amortization Expense, Year Two	357
Finite-Lived Intangible Assets, Amortization Expense, Year Three	357
Finite-Lived Intangible Assets, Amortization Expense, Year Four	357
Finite-Lived Intangible Assets, Amortization Expense, Year Five	357
Transportation and Storage Capacity [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	267	267
Finite-Lived Intangible Assets, Accumulated Amortization	(172)	(14)
Amortization of Intangible Assets	158	14
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	51
Finite-Lived Intangible Assets, Amortization Expense, Year Two	21
Finite-Lived Intangible Assets, Amortization Expense, Year Three	10
Finite-Lived Intangible Assets, Amortization Expense, Year Four	7
Finite-Lived Intangible Assets, Amortization Expense, Year Five	4
Other Intangible Assets [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross	6	6
Finite-Lived Intangible Assets, Accumulated Amortization	$ (2)	$ (2)

XML

Accrued and Other Current Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Accrued Liabilities [Line Items]
Interest on debt	$ 274	$ 277
Employee costs	218	214
Regulatory Liabilities, Current	201	56
Contract liabilities	141	134
Asset Retirement Obligation, Current	87	75
Operating Lease, Liability, Current	25	23
Other, including accrued loss contingencies	324	256
Other accrued liabilities	$ 1,270	$ 1,035

XML

Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2022	Oct. 17, 2022	Aug. 08, 2022	May 16, 2022	Jan. 18, 2022	Dec. 31, 2021	Oct. 08, 2021	Mar. 02, 2021	May 14, 2020	May 08, 2020
Long-term Debt
Unamortized debt issuance costs	$ (135)					$ (131)
Net unamortized debt premium (discount)	(55)					(56)
Total long-term debt, including current portion	22,554					23,675
Long-term debt due within one year	(627)					(2,025)
Long-term debt	21,927					21,650
Transcontinental Gas Pipe Line Company, LLC [Member] | 7.08% Debentures Due 2026 [Member]
Long-term Debt
Long-term debt	$ 8					8
Long-term debt interest rate	7.08%
Transcontinental Gas Pipe Line Company, LLC [Member] | 7.25% Debentures Due 2026 [Member]
Long-term Debt
Long-term debt	$ 200					200
Long-term debt interest rate	7.25%
Transcontinental Gas Pipe Line Company, LLC [Member] | 7.85% Senior Unsecured Notes Due 2026 [Member]
Long-term Debt
Long-term debt	$ 1,000					1,000
Long-term debt interest rate	7.85%
Transcontinental Gas Pipe Line Company, LLC [Member] | 4% Senior Unsecured Notes Due 2028 [Member]
Long-term Debt
Long-term debt	$ 400					400
Long-term debt interest rate	4.00%
Transcontinental Gas Pipe Line Company, LLC [Member] | 3.25 Percent Senior Unsecured Notes Due 2030 [Member]
Long-term Debt
Long-term debt	$ 700					700
Long-term debt interest rate	3.25%									3.25%
Transcontinental Gas Pipe Line Company, LLC [Member] | 5.4% Senior Unsecured Notes Due 2041 [Member]
Long-term Debt
Long-term debt	$ 375					375
Long-term debt interest rate	5.40%
Transcontinental Gas Pipe Line Company, LLC [Member] | 4.45% Senior Unsecured Notes Due 2042 [Member]
Long-term Debt
Long-term debt	$ 400					400
Long-term debt interest rate	4.45%
Transcontinental Gas Pipe Line Company, LLC [Member] | 4.6% Senior Unsecured Notes Due 2048 [Member]
Long-term Debt
Long-term debt	$ 600					600
Long-term debt interest rate	4.60%
Transcontinental Gas Pipe Line Company, LLC [Member] | 3.95 Percent Senior Unsecured Notes Due 2050 [Member]
Long-term Debt
Long-term debt	$ 500					500
Long-term debt interest rate	3.95%									3.95%
Transcontinental Gas Pipe Line Company, LLC [Member] | Atlantic Sunrise [Member]
Long-term Debt
Other financing obligations	$ 809					830
Long-term debt interest rate	9.00%
Transcontinental Gas Pipe Line Company, LLC [Member] | Leidy South
Long-term Debt
Other financing obligations	$ 77					72
Long-term debt interest rate	13.00%
Transcontinental Gas Pipe Line Company, LLC [Member] | Dalton [Member]
Long-term Debt
Other financing obligations	$ 252					254
Long-term debt interest rate	9.00%
Northwest Pipeline LLC [Member] | 7.125% Debentures Due 2025 [Member]
Long-term Debt
Long-term debt	$ 85					85
Long-term debt interest rate	7.125%
Northwest Pipeline LLC [Member] | 4% Senior Unsecured Notes Due 2027 [Member]
Long-term Debt
Long-term debt	$ 500					500
Long-term debt interest rate	4.00%
The Williams Companies, Inc. [Member]
Long-term Debt
Credit facility loans	$ 0
The Williams Companies, Inc. [Member] | 3.35% Senior Unsecured Notes Due 2022 [Member]
Long-term Debt
Long-term debt	$ 0					750
Long-term debt interest rate	3.35%			3.35%
The Williams Companies, Inc. [Member] | 3.6% Senior Unsecured Notes Due 2022 [Member]
Long-term Debt
Long-term debt	$ 0					1,250
Long-term debt interest rate	3.60%				3.60%
The Williams Companies, Inc. [Member] | 3.7% Senior Unsecured Notes Due 2023 [Member]
Long-term Debt
Long-term debt	$ 0					850
Long-term debt interest rate	3.70%	3.70%
The Williams Companies, Inc. [Member] | 4.5% Senior Unsecured Notes Due 2023 [Member]
Long-term Debt
Long-term debt	$ 600					600
Long-term debt interest rate	4.50%
The Williams Companies, Inc. [Member] | 4.3% Senior Unsecured Notes Due 2024 [Member]
Long-term Debt
Long-term debt	$ 1,000					1,000
Long-term debt interest rate	4.30%
The Williams Companies, Inc. [Member] | 4.55% Senior Unsecured Notes Due 2024 [Member]
Long-term Debt
Long-term debt	$ 1,250					1,250
Long-term debt interest rate	4.55%
The Williams Companies, Inc. [Member] | 3.9% Senior Unsecured Notes Due 2025 [Member]
Long-term Debt
Long-term debt	$ 750					750
Long-term debt interest rate	3.90%
The Williams Companies, Inc. [Member] | 4% Senior Unsecured Notes Due 2025 [Member]
Long-term Debt
Long-term debt	$ 750					750
Long-term debt interest rate	4.00%
The Williams Companies, Inc. [Member] | 3.75% Senior Unsecured Notes Due 2027 [Member]
Long-term Debt
Long-term debt	$ 1,450					1,450
Long-term debt interest rate	3.75%
The Williams Companies, Inc. [Member] | 3.5 Percent Senior Unsecured Notes Due 2030 [Member]
Long-term Debt
Long-term debt	$ 1,000					1,000
Long-term debt interest rate	3.50%								3.50%
The Williams Companies, Inc. [Member] | 7.5% Debentures Due 2031 [Member]
Long-term Debt
Long-term debt	$ 339					339
Long-term debt interest rate	7.50%
The Williams Companies, Inc. [Member] | 7.75% Senior Unsecured Notes Due 2031 [Member]
Long-term Debt
Long-term debt	$ 252					252
Long-term debt interest rate	7.75%
The Williams Companies, Inc. [Member] | 8.75% Senior Unsecured Notes Due 2032 [Member]
Long-term Debt
Long-term debt	$ 445					445
Long-term debt interest rate	8.75%
The Williams Companies, Inc. [Member] | 6.3% Senior Unsecured Notes Due 2040 [Member]
Long-term Debt
Long-term debt	$ 1,250					1,250
Long-term debt interest rate	6.30%
The Williams Companies, Inc. [Member] | 5.8% Senior Unsecured Notes Due 2043 [Member]
Long-term Debt
Long-term debt	$ 400					400
Long-term debt interest rate	5.80%
The Williams Companies, Inc. [Member] | 5.4% Senior Unsecured Notes Due 2044 [Member]
Long-term Debt
Long-term debt	$ 500					500
Long-term debt interest rate	5.40%
The Williams Companies, Inc. [Member] | 5.75% Senior Unsecured Notes Due 2044 [Member]
Long-term Debt
Long-term debt	$ 650					650
Long-term debt interest rate	5.75%
The Williams Companies, Inc. [Member] | 4.9% Senior Unsecured Notes Due 2045 [Member]
Long-term Debt
Long-term debt	$ 500					500
Long-term debt interest rate	4.90%
The Williams Companies, Inc. [Member] | 5.1% Senior Unsecured Notes Due 2045 [Member]
Long-term Debt
Long-term debt	$ 1,000					1,000
Long-term debt interest rate	5.10%
The Williams Companies, Inc. [Member] | 4.85 Percent Senior Unsecured Notes Due 2048 [Member]
Long-term Debt
Long-term debt	$ 800					800
Long-term debt interest rate	4.85%
The Williams Companies, Inc. [Member] | 3.5 Percent Senior Unsecured Notes Due 2051
Long-term Debt
Long-term debt	$ 650					650
Long-term debt interest rate	3.50%						3.50%
The Williams Companies, Inc. [Member] | 2.6 Percent Senior Unsecured Notes Due 2031
Long-term Debt
Long-term debt	$ 1,500					1,500
Long-term debt interest rate	2.60%						2.60%	2.60%
The Williams Companies, Inc. [Member] | Various - 7.7% to 8.72% Notes due 2022 to 2027 [Member]
Long-term Debt
Long-term debt	$ 2					2
The Williams Companies, Inc. [Member] | Various - 7.7 to 8.72 Percent Notes Due 2022 to 2027 Minimum Interest Rate [Member]
Long-term Debt
Long-term debt interest rate	7.70%
The Williams Companies, Inc. [Member] | Various - 7.7% to 8.72% Notes Due 2022 to 2027 Maximum Interest Rate [Member]
Long-term Debt
Long-term debt interest rate	8.72%
The Williams Companies, Inc. [Member] | 4.65 Percent Senior Unsecured Notes Due 2032
Long-term Debt
Long-term debt	$ 1,000					0
Long-term debt interest rate	4.65%		4.65%
The Williams Companies, Inc. [Member] | 5.3 Percent Senior Unsecured Notes Due 2052
Long-term Debt
Long-term debt	$ 750					$ 0
Long-term debt interest rate	5.30%		5.30%

XML

Long-Term Debt Maturities (Details) $ in Millions	Dec. 31, 2022 USD ($)
Aggregate minimum maturities of long-term debt
2023	$ 629
2024	2,281
2025	1,619
2026	1,245
2027	$ 1,993

XML

Long-Term Debt Issuances and Retirements (Details) - USD ($) $ in Millions	Oct. 17, 2022	May 16, 2022	Jan. 18, 2022	Sep. 01, 2021	Aug. 16, 2021	Aug. 17, 2020	Mar. 15, 2020	Jan. 15, 2020	Dec. 31, 2022	Aug. 08, 2022	Dec. 31, 2021	Oct. 08, 2021	Mar. 02, 2021	May 14, 2020	May 08, 2020
The Williams Companies, Inc. [Member] | 3.7% Senior Unsecured Notes Due 2023 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	$ 850
Long-term debt interest rate	3.70%								3.70%
Long-term debt									$ 0		$ 850
The Williams Companies, Inc. [Member] | 4.65 Percent Senior Unsecured Notes Due 2032
Debt Instrument [Line Items]
Long-term debt interest rate									4.65%	4.65%
Long-term debt face amount										$ 1,000
Long-term debt									$ 1,000		0
The Williams Companies, Inc. [Member] | 5.3 Percent Senior Unsecured Notes Due 2052
Debt Instrument [Line Items]
Long-term debt interest rate									5.30%	5.30%
Long-term debt face amount										$ 750
Long-term debt									$ 750		0
The Williams Companies, Inc. [Member] | 3.35% Senior Unsecured Notes Due 2022 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount		$ 750
Long-term debt interest rate		3.35%							3.35%
Long-term debt									$ 0		750
The Williams Companies, Inc. [Member] | 3.6% Senior Unsecured Notes Due 2022 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount			$ 1,250
Long-term debt interest rate			3.60%						3.60%
Long-term debt									$ 0		1,250
The Williams Companies, Inc. [Member] | 2.6 Percent Senior Unsecured Notes Due 2031
Debt Instrument [Line Items]
Long-term debt interest rate									2.60%			2.60%	2.60%
Long-term debt face amount												$ 600	$ 900
Long-term debt									$ 1,500		1,500
The Williams Companies, Inc. [Member] | 3.5 Percent Senior Unsecured Notes Due 2051
Debt Instrument [Line Items]
Long-term debt interest rate									3.50%			3.50%
Long-term debt face amount												$ 650
Long-term debt									$ 650		650
The Williams Companies, Inc. [Member] | 7.875% Senior Unsecured Notes Due 2021 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount				$ 371
Long-term debt interest rate				7.875%
The Williams Companies, Inc. [Member] | 4% Senior Unsecured Notes Due 2021 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount					$ 500
Long-term debt interest rate					4.00%
The Williams Companies, Inc. [Member] | 4.125% Senior Unsecured Notes Due 2020 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount						$ 600
Long-term debt interest rate						4.125%
The Williams Companies, Inc. [Member] | 3.5 Percent Senior Unsecured Notes Due 2030 [Member]
Debt Instrument [Line Items]
Long-term debt interest rate									3.50%					3.50%
Long-term debt face amount														$ 1,000
Long-term debt									$ 1,000		1,000
The Williams Companies, Inc. [Member] | 5.25% Senior Unsecured Notes Due 2020 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount							$ 1,500
Long-term debt interest rate							5.25%
The Williams Companies, Inc. [Member] | 8.75 Percent Senior Unsecured Notes Due 2020 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount								$ 14
Long-term debt interest rate								8.75%
Transcontinental Gas Pipe Line Company, LLC [Member] | 3.25 Percent Senior Unsecured Notes Due 2030 [Member]
Debt Instrument [Line Items]
Long-term debt interest rate									3.25%						3.25%
Long-term debt face amount															$ 700
Long-term debt									$ 700		700
Transcontinental Gas Pipe Line Company, LLC [Member] | 3.95 Percent Senior Unsecured Notes Due 2050 [Member]
Debt Instrument [Line Items]
Long-term debt interest rate									3.95%						3.95%
Long-term debt face amount															$ 500
Long-term debt									$ 500		$ 500
Transcontinental Gas Pipe Line Company, LLC [Member] | Atlantic Sunrise [Member]
Debt Instrument [Line Items]
Long-term debt interest rate									9.00%
Transcontinental Gas Pipe Line Company, LLC [Member] | Leidy South
Debt Instrument [Line Items]
Long-term debt interest rate									13.00%
Transcontinental Gas Pipe Line Company, LLC [Member] | Dalton [Member]
Debt Instrument [Line Items]
Long-term debt interest rate									9.00%

XML

Credit Facility and Commercial Paper (Details) $ in Millions	Oct. 08, 2021 USD ($)	Aug. 10, 2018 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Sep. 30, 2021 USD ($)
Credit Facility and Commercial Paper [Line Items]
Commercial paper, outstanding			$ 350	$ 0
Short-Term Debt, Weighted Average Interest Rate, at Point in Time			4.80%
Williams Companies Inc [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	$ 3,750		$ 3,750		$ 4,500
Credit facility, loans outstanding			0
Additional amount by which credit facility can be increased	$ 500
Maximum ratio of debt to EBITDA after acquisition	5.5
Acquisition Trigger Amount	$ 25
Williams Companies Inc [Member] | Swing Line Loan [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	200
Williams Companies Inc [Member] | Commercial paper [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	3,500	$ 4,000
Commercial paper, outstanding			350	$ 0
Commercial paper, maximum maturity		397 days
Williams Companies Inc [Member] | Letters of credit [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	$ 500
Williams Companies Inc [Member] | Letters Of Credit Under Certain Bilateral Bank Agreements [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, letters of credit outstanding			$ 30
Transcontinental Gas Pipe Line Company, LLC [Member]
Credit Facility and Commercial Paper [Line Items]
Maximum ratio of debt to capitalization	65.00%
Transcontinental Gas Pipe Line Company, LLC [Member] | Letters of credit [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	$ 500
Northwest Pipeline LLC [Member]
Credit Facility and Commercial Paper [Line Items]
Maximum ratio of debt to capitalization	65.00%
Northwest Pipeline LLC [Member] | Letters of credit [Member]
Credit Facility and Commercial Paper [Line Items]
Credit facility, capacity	$ 500
Dec21 And Subsequent Quarters [Member] | Williams Companies Inc [Member]
Credit Facility and Commercial Paper [Line Items]
Maximum ratio of debt to EBITDA	5.0

XML

Cash Payments For Interest (Net of Amounts Capitalized) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Debt Disclosure [Abstract]
Cash payments for interest (net of amounts capitalized)	$ 1,117	$ 1,137	$ 1,149

XML

Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Lessee, Lease, Description [Line Items]
Operating Lease, Cost	$ 34	$ 35	$ 37
Variable Lease, Cost	26	15	19
Sublease Income	0	(1)	(1)
Lease, Cost	60	49	55
Operating Lease, Payments	$ 33	$ 35	$ 30
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other Assets, Noncurrent	Other Assets, Noncurrent
Operating Lease, Right-of-Use Asset	$ 162	$ 159
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Accrued Liabilities, Current	Accrued Liabilities, Current
Operating Lease, Liability, Current	$ 25	$ 23
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Liabilities and Deferred Revenue, Noncurrent	Other Liabilities and Deferred Revenue, Noncurrent
Operating Lease, Liability, Noncurrent	$ 148	$ 141
Operating Lease, Weighted Average Remaining Lease Term	13 years	13 years
Operating Lease, Weighted Average Discount Rate, Percent	4.62%	4.56%
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months	$ 31
Lessee, Operating Lease, Liability, Payments, Due Year Two	26
Lessee, Operating Lease, Liability, Payments, Due Year Three	20
Lessee, Operating Lease, Liability, Payments, Due Year Four	20
Lessee, Operating Lease, Liability, Payments, Due Year Five	19
Lessee, Operating Lease, Liability, Payments, Due after Year Five	122
Lessee, Operating Lease, Liability, Payments, Due	238
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	65
Other Liabilities
Lessee, Lease, Description [Line Items]
Operating Lease, Liability	$ 173

XML

Equity-Based Compensation (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Apr. 28, 2020
Williams Companies Incentive Plan [Member]
Equity-Based Compensation (Textuals) [Abstract]
Shares authorized for issuance	50,000			10,000
Shares reserved for future issuance	25,000
Shares available for future grants	15,000
Equity-based compensation expense	$ 73	$ 81	$ 52
Tax benefit from equity-based compensation expense	18	$ 20	$ 13
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized [Abstract]
Unrecognized equity-based compensation expense	$ 63
Unrecognized equity-based compensation expense, Weighted-average period of recognition in years	1 year 8 months 12 days
Williams Companies Incentive Plan [Member] | Nonvested Restricted Stock Units [Member]
Rollforward of nonvested restricted stock unit activity and related information
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	6,900	7,300
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 23.63	$ 22.35
Williams Companies Incentive Plan [Member] | Performance Shares [Member]
Rollforward of nonvested restricted stock unit activity and related information
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	2,600
Williams Companies Incentive Plan [Member] | Performance Shares [Member] | Minimum [Member]
Rollforward of nonvested restricted stock unit activity and related information
Range of vested shares based on extent to which certain financial targets are achieved	0.00%
Williams Companies Incentive Plan [Member] | Performance Shares [Member] | Maximum [Member]
Rollforward of nonvested restricted stock unit activity and related information
Range of vested shares based on extent to which certain financial targets are achieved	200.00%
Williams Companies Incentive Plan [Member] | Stock options [Member]
Rollforward of stock option activity and related information
Options, Granted	0	0	0
Options Outstanding, Ending Balance	2,800
Options Exercisable at Period End	2,800
Options, Weighted Average Exercise Price, Ending Balance	$ 34.32
Options, Weighted Average Exercise Price, Exercisable at Period End	$ 34.32
Stock Options Outstanding, Weighted Average Remaining Contractual Life	2 years 9 months 18 days
Stock Options Exercisable, Weighted Average Remaining Contractual Life	2 years 9 months 18 days
Proceeds from Stock Options Exercised	$ 49
Tax benefits realized on options exercised	$ 2
Employee Stock Purchase Plan [Member]
Equity-Based Compensation (Textuals) [Abstract]
Shares authorized for issuance	5,200			1,600
Shares available for future grants	1,200
No. of shares purchases by employees	242
Average price of shares purchased	$ 24.57

XML

Fair Value Measurements and Guarantees Recurring Measurements and Additional (Details) - USD ($) $ in Millions	Dec. 31, 2022		Dec. 31, 2021
Additional disclosures:
Collateral Already Posted, Aggregate Fair Value	$ 202		$ 296
Derivative Asset, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Assets, Noncurrent
Derivative Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Liabilities and Deferred Revenue, Noncurrent
Carrying Amount [Member]
Additional disclosures:
Long-term debt, including current portion	$ (22,554)		(23,675)
Guarantees	(38)		(39)
Fair Value [Member]
Additional disclosures:
Long-term debt, including current portion	(21,569)		(27,768)
Guarantees	(25)		(26)
Level 1 [Member]
Additional disclosures:
Long-term debt, including current portion	0		0
Guarantees	0		0
Collateral Already Posted, Aggregate Fair Value	202		296
Level 2 [Member]
Additional disclosures:
Long-term debt, including current portion	(21,569)		(27,768)
Guarantees	(9)		(10)
Level 3 [Member]
Additional disclosures:
Long-term debt, including current portion	0		0
Guarantees	(16)		(16)
Fair Value, Recurring [Member] | Carrying Amount [Member]
Measured on a recurring basis
ARO Trust investments	230		260
Derivative Asset, Fair Value, Gross Asset	166	[1]	84	[2]
Derivative Liability, Fair Value, Gross Liability	(810)	[1]	(488)	[2]
Financial Liabilities Fair Value Disclosure	(5)		(7)
Fair Value, Recurring [Member] | Fair Value [Member]
Measured on a recurring basis
ARO Trust investments	230		260
Derivative Asset, Fair Value, Gross Asset	166	[1]	84	[2]
Derivative Liability, Fair Value, Gross Liability	(810)	[1]	(488)	[2]
Financial Liabilities Fair Value Disclosure	(5)		(7)
Fair Value, Recurring [Member] | Level 1 [Member]
Measured on a recurring basis
ARO Trust investments	230		260
Derivative Asset, Fair Value, Gross Asset	20	[1]	2	[2]
Derivative Liability, Fair Value, Gross Liability	(22)	[1]	(69)	[2]
Financial Liabilities Fair Value Disclosure	0		0
Fair Value, Recurring [Member] | Level 2 [Member]
Measured on a recurring basis
ARO Trust investments	0		0
Derivative Asset, Fair Value, Gross Asset	132	[1]	81	[2]
Derivative Liability, Fair Value, Gross Liability	(718)	[1]	(403)	[2]
Financial Liabilities Fair Value Disclosure	(5)		(7)
Fair Value, Recurring [Member] | Level 3 [Member]
Measured on a recurring basis
ARO Trust investments	0		0
Derivative Asset, Fair Value, Gross Asset	14	[1]	1	[2]
Derivative Liability, Fair Value, Gross Liability	(70)	[1]	(16)	[2]
Financial Liabilities Fair Value Disclosure	0		$ 0
Wiltel Guarantee [Member]
Additional disclosures:
Guarantor Obligations, Maximum Exposure, Undiscounted	24
Indemnification Agreement [Member] | Carrying Amount [Member]
Additional disclosures:
Guarantees	$ 0

[1] Net commodity derivative assets and liabilities exclude $202 million of net cash collateral in Level 1.

[2] Net commodity derivative assets and liabilities exclude $296 million of net cash collateral in Level 1.

XML

Fair Value Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance at beginning of period	$ (15)	$ (2)
Gains (losses) included in the Consolidated Statement of Income	(31)	(62)
Purchases, issuances, and settlements	(5)	13
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	(24)	0
Transfers out of Level 3	19	12
Balance at end of period	(56)	(15)
Sequent Acquisition
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers into Level 3	$ 0	$ 24

XML

Fair Value Measurements Nonrecurring Measurements (Details) - USD ($) $ in Millions							1 Months Ended		3 Months Ended		12 Months Ended
		Jun. 30, 2021	Dec. 31, 2020		Mar. 31, 2020		Mar. 31, 2020		Mar. 31, 2020		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of certain assets (Note 15)											$ 0	$ 2	$ 182
Impairment of equity-method investments											0	0	1,046
Share Price Change							26.00%		40.00%
Goodwill, Impairment Loss											0	0	187
Noncontrolling Interests
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Goodwill, Impairment Loss									$ 65
Level 3 [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Goodwill, Impairment Loss									187
Level 3 [Member] | Property, plant, and equipment, net [Member] | Transmission And Gulf Of Mexico [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of property, plant, and equipment	[1]	$ 1	$ 42										42
Level 3 [Member] | Investments [Member] | Transmission And Gulf Of Mexico [Member] | Discovery Producer Services LLC [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of investment	[2]				$ 367		$ 367		367
Level 3 [Member] | Investments [Member] | Northeast G And P [Member] | Blue Racer Midstream Holdings LLC | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of investment	[2]				191		191		191
Level 3 [Member] | Investments [Member] | Northeast G And P [Member] | Aux Sable Liquid Products LP [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of investment	[2]				7		7		7
Level 3 [Member] | Investments [Member] | Northeast G And P [Member] | Laurel Mountain Midstream, LLC [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of investment	[2]				236		236		236
Level 3 [Member] | Investments [Member] | West [Member] | Rocky Mountain Midstream Holdings LLC [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of investment			421	[3]	557	[4]	557	[4]	557	[4]			421	[3]
Level 3 [Member] | Investments [Member] | West [Member] | Brazos Permian II, LLC [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of investment	[4]				0		$ 0		$ 0
Level 2 [Member] | Property Plant And Equipment, Net And Intangible Assets, Net Of Accumulated Amortization [Member] | Northeast G And P [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Property Plant And Equipment And Intangibles, Fair Value Disclosure	[5]		5										5
Impairment Of Certain Assets [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of certain assets (Note 15)											0	2	182
Impairment Of Certain Assets [Member] | Level 3 [Member] | Transmission And Gulf Of Mexico [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of certain assets	[1]	$ 2	170
Impairment Of Certain Assets [Member] | Level 2 [Member] | Northeast G And P [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of certain assets (Note 15)	[5]		12
Impairment Of Equity-Method Investments [Member] | Level 3 [Member] | Transmission And Gulf Of Mexico [Member] | Discovery Producer Services LLC [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments	[2]				97
Impairment Of Equity-Method Investments [Member] | Level 3 [Member] | Northeast G And P [Member] | Blue Racer Midstream Holdings LLC | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments	[2]				229
Impairment Of Equity-Method Investments [Member] | Level 3 [Member] | Northeast G And P [Member] | Aux Sable Liquid Products LP [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments	[2]				39
Impairment Of Equity-Method Investments [Member] | Level 3 [Member] | Northeast G And P [Member] | Laurel Mountain Midstream, LLC [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments	[2]				10
Impairment Of Equity-Method Investments [Member] | Level 3 [Member] | West [Member] | Rocky Mountain Midstream Holdings LLC [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments			$ 108	[3]	243	[4]
Impairment Of Equity-Method Investments [Member] | Level 3 [Member] | West [Member] | Brazos Permian II, LLC [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments	[4]				$ 193
Impairment Of Equity-Method Investments [Member] | Fair Value, Inputs, Level 1, 2 and 3 [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments											$ 0	$ 0	$ 1,046
Measurement Input, Discount Rate [Member] | Rocky Mountain Midstream Holdings LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Investments Fair Value Inputs					17.00%		17.00%		17.00%			18.00%
Measurement Input, Discount Rate [Member] | Brazos Permian II, LLC [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Investments Fair Value Inputs					17.00%		17.00%		17.00%
Measurement Input, Discount Rate [Member] | Appalachia Midstream Services LLC And Laurel Mountain Midstream LLC And Discovery Producer Services LLC [Member] | Minimum [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Investments Fair Value Inputs					9.70%		9.70%		9.70%
Measurement Input, Discount Rate [Member] | Appalachia Midstream Services LLC And Laurel Mountain Midstream LLC And Discovery Producer Services LLC [Member] | Maximum [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Investments Fair Value Inputs					13.50%		13.50%		13.50%
Measurement Input, Discount Rate [Member] | Appalachia Midstream Services LLC And Laurel Mountain Midstream LLC And Discovery Producer Services LLC [Member] | Weighted Average [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Investments Fair Value Inputs					12.60%		12.60%		12.60%
Measurement Input, EBITDA Multiple [Member] | Blue Racer Midstream Holdings LLC And Aux Sable Liquid Products LP | Minimum [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Investments Fair Value Inputs					500.00%		500.00%		500.00%
Measurement Input, EBITDA Multiple [Member] | Blue Racer Midstream Holdings LLC And Aux Sable Liquid Products LP | Maximum [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Investments Fair Value Inputs					620.00%		620.00%		620.00%
Measurement Input, EBITDA Multiple [Member] | Blue Racer Midstream Holdings LLC And Aux Sable Liquid Products LP | Weighted Average [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Investments Fair Value Inputs					600.00%		600.00%		600.00%
Williams Companies Inc [Member] | Level 3 [Member] | Investments [Member] | Northeast G And P [Member] | Appalachia Midstream Services, LLC [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Fair value of investment	[2]				$ 2,700		$ 2,700		$ 2,700
Williams Companies Inc [Member] | Impairment Of Equity-Method Investments [Member] | Level 3 [Member] | Northeast G And P [Member] | Appalachia Midstream Services, LLC [Member] | Fair Value, Nonrecurring [Member]
Fair Value Assets Measured On Nonrecurring Basis [Abstract]
Impairment of equity-method investments	[2]				$ 127

[1] Relates to capitalized project development costs for the Northeast Supply Enhancement project. Approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection have been denied and we have not refiled at this time. Beginning in May 2020, we discontinued capitalization of costs related to this project. Considering that the customer precedent agreements and FERC certificate for the project remain in effect, we had previously concluded that the probability of completing the project was sufficient to not require impairment. However, developments in the political and regulatory environments caused us to slightly lower that assessed probability such that the capitalized project costs required impairment. The estimated fair value of the materials within the capitalized project costs at December 31, 2020 considered other internal uses and salvage values for the Property, plant, and equipment – net. The remaining capitalized costs were determined to have no fair value. The estimated fair value of certain capitalized project costs at June 30, 2021, was determined by a market approach, which incorporated an indication of interest by a third-party.

[2] Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The impairments within our Northeast G&P segment are primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices which historically trend with crude oil prices. The fair values of our investments in BRMH and Aux Sable Liquid Products LP (Aux Sable) were estimated using a market approach, reflecting valuation multiples ranging from 5.0x to 6.2x EBITDA (weighted-average 6.0x). The fair values of the other investments, including gathering systems that are part of Appalachia Midstream Investments, were estimated using an income approach, with discount rates ranging from 9.7 percent to 13.5 percent (weighted-average 12.6 percent). We also considered any debt held at the investee level, and its impact to fair value. The assumed valuation multiples and industry weighted-average discount rates utilized were both significantly influenced by the market declines previously discussed.

[3] During the fourth quarter of 2020, RMM renegotiated service contracts with a significant customer in connection with the customer’s Chapter 11 bankruptcy proceedings. The renegotiated contracts result in lower service rates and lower projected future cash flows. As a result, we evaluated this investment for other-than-temporary impairment. The fair value was measured using an income approach. We utilized a discount rate of 18 percent in our analysis

[4] Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The fair value was measured using an income approach. Both investees operate in primarily oil-driven basins where significant expected reductions in producer activities led to reduced estimates of expected future cash flows. Our fair value estimates also reflected discount rates of approximately 17 percent for these investments. We also considered any debt held at the investee level, and its impact to fair value. The industry weighted-average discount rates utilized were significantly influenced by the market declines previously discussed.

[5] Relates to a gathering system in the Marcellus Shale region, that was sold in 2021. The estimated fair value of the Property, plant, and equipment – net and Intangible assets – net of accumulated amortization was determined using a market approach, which incorporated an indication of interest by a third party. These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy.

XML

Fair Value Measurements Concentration of Credit Risk (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Concentration Risk [Line Items]
Trade accounts and other receivables – net	$ 2,723	$ 1,978
NGLs, natural gas, and related products and services [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables – net	505	486
Transportation of natural gas and related products [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables – net	311	274
Marketing Of Natural Gas And NGLs
Concentration Risk [Line Items]
Trade accounts and other receivables – net	858	609
Oil and Gas, Exploration and Production
Concentration Risk [Line Items]
Trade accounts and other receivables – net	97	82
Accounts Receivable related to revenues from contracts with customers [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables – net	1,771	1,451
Derivative Receivables
Concentration Risk [Line Items]
Trade accounts and other receivables – net	889	462
Other Receivable [Member]
Concentration Risk [Line Items]
Trade accounts and other receivables – net	$ 63	$ 65

XML

Derivatives - Commodity Related Derivatives (Details) - Not Designated as Hedging Instrument [Member]	Dec. 31, 2022 MMBTU Boe
Public Utilities, Inventory, Natural Gas | IndexRisk
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Nonmonetary Notional Amount Net Long Short Position Volume | MMBTU	745,415,032
Public Utilities, Inventory, Natural Gas | Central Hub Risk
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Nonmonetary Notional Amount Net Long Short Position Volume | MMBTU	(46,154,200)
Public Utilities, Inventory, Natural Gas | Basis Risk
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Nonmonetary Notional Amount Net Long Short Position Volume | MMBTU	(50,737,802)
Natural Gas Liquids | Central Hub Risk
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Nonmonetary Notional Amount Net Long Short Position Volume | Boe	35,548
Natural Gas Liquids | Basis Risk
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Nonmonetary Notional Amount Net Long Short Position Volume | Boe	(3,880,364)
Crude Oil | Central Hub Risk
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Nonmonetary Notional Amount Net Long Short Position Volume | Boe	(123,250)

XML

Derivatives - Financial Statement Presentation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Liability	$ (1,034)	$ (476)
Derivative Liability, Fair Value, Gross Asset	1,236	772
Derivative Asset	334	309
Derivative Liability	(776)	(417)
Energy Related Derivative | Gain (Loss) on Derivative Instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative Instruments, Net, Pretax	(387)	(148)	$ (5)
Designated as Hedging Instrument | Energy Related Derivative | Gain (Loss) on Derivative Instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	(55)	(2)
Not Designated as Hedging Instrument [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,368	785
Derivative Liability, Fair Value, Gross Liability	(2,012)	(1,189)
Not Designated as Hedging Instrument [Member] | Energy Related Derivative | Gain (Loss) on Derivative Instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(91)	16	(3)
Unrealized Gain (Loss) on Derivatives	(296)	(109)	0
Not Designated as Hedging Instrument [Member] | Energy Related Derivative | Cost of Sales
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Gain (Loss) on Derivative, Net	16	2	1
Unrealized Gain (Loss) on Derivatives	47	0	$ 0
Other Current Liabilities | Not Designated as Hedging Instrument [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,099	619
Derivative Liability, Fair Value, Gross Liability	(1,278)	(760)
Regulatory liabilities, deferred income, and other [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset, Fair Value, Gross Asset	269	166
Derivative Liability, Fair Value, Gross Liability	$ (734)	$ (429)

XML

Derivatives - Contingent Features (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Additional Collateral, Aggregate Fair Value	$ 13
Collateral Already Posted, Aggregate Fair Value	$ 202	$ 296

XML

Contingent Liabilities and Commitments (Details) - USD ($) $ in Millions				1 Months Ended
	Sep. 21, 2022	Dec. 29, 2021	May 20, 2016	Jan. 31, 2020	Dec. 31, 2022
Loss Contingencies [Line Items]
Accrued environmental loss liabilities					$ 40
Environmental Loss Contingency, Statement of Financial Position [Extensible Enumeration]					Accrued Liabilities, Current
Capital Addition Purchase Commitments [Member]
Loss Contingencies [Line Items]
Commitments for construction and acquisition of property, plant, and equipment					$ 439
Gas & NGL Marketing Services
Loss Contingencies [Line Items]
Other Commitment					546
Former Alaska Refinery [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Awarded, Value				$ 86
Energy Transfer Merger [Member]
Loss Contingencies [Line Items]
Loss contingency, damages sought, value			$ 1,480
Litigation Settlement, Amount Awarded from Other Party	$ 602	$ 410
Gas Pipeline [Member]
Loss Contingencies [Line Items]
Accrued environmental loss liabilities					13
Natural Gas Underground Storage Facilities [Member]
Loss Contingencies [Line Items]
Accrued environmental loss liabilities					10
Former Operations [Member]
Loss Contingencies [Line Items]
Accrued environmental loss liabilities					17
Recoverable through rates [Member]
Loss Contingencies [Line Items]
Accrued environmental loss liabilities					$ 4

XML

Segment Disclosures Recon from Modified EBITDA to Net Income (Loss) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA		$ 6,075	$ 5,494	$ 4,851
Accretion expense associated with asset retirement obligations for nonregulated operations		(51)	(45)	(35)
Depreciation and amortization expenses		(2,009)	(1,842)	(1,721)
Impairment of goodwill (Note 15)		0	0	(187)
Equity earnings (losses) (Note 8)		637	608	328
Impairment of equity-method investments (Note 17)		0	0	(1,046)
Other investing income (loss) – net		16	7	8
Proportional Modified EBITDA Equity Method Investments		(979)	(970)	(749)
Interest Expense		(1,147)	(1,179)	(1,172)
(Provision) benefit for income taxes		(425)	(511)	(79)
Net income (loss)		2,117	1,562	198
Inventory write-downs		161	15	17
Energy Related Derivative | Not Designated as Hedging Instrument [Member] | Cost of Sales
Reconciliation of Modified EBITDA to Net Income (Loss)
Unrealized Gain (Loss) on Derivatives		47	0	0
Gas & NGL Marketing Services | Energy Related Derivative | Not Designated as Hedging Instrument [Member] | Cost of Sales
Reconciliation of Modified EBITDA to Net Income (Loss)
Unrealized Gain (Loss) on Derivatives		47	0	0
Intersegment Eliminations [Member]
Reconciliation of Modified EBITDA to Net Income (Loss)
Proportional Modified EBITDA Equity Method Investments		0	0	0
Operating Segments [Member] | Transmission And Gulf Of Mexico [Member]
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA		2,674	2,621	2,379
Proportional Modified EBITDA Equity Method Investments		(193)	(183)	(166)
Operating Segments [Member] | Northeast G And P [Member]
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA		1,796	1,712	1,489
Proportional Modified EBITDA Equity Method Investments		(654)	(682)	(473)
Operating Segments [Member] | West [Member]
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA		1,211	961	947
Proportional Modified EBITDA Equity Method Investments		(132)	(105)	(110)
Operating Segments [Member] | Gas & NGL Marketing Services
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA	[1]	(40)	22	51
Proportional Modified EBITDA Equity Method Investments		0	0	0
Operating Segments [Member] | Other [Member]
Reconciliation of Modified EBITDA to Net Income (Loss)
Modified EBITDA		434	178	(15)
Proportional Modified EBITDA Equity Method Investments		$ 0	$ 0	$ 0

[1] Modified EBITDA for 2022, 2021, and 2020, includes charges of $161 million, $15 million, and $17 million respectively, associated with lower of cost or net realizable value adjustments to our inventory. These charges are reflected in Product Sales or Product costs in our Consolidated Statement of Income (see Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies). Net unrealized commodity-related derivatives gains of $47 million in 2022 and $0 in 2021 and 2020 are reflected in Net processing commodity expenses.

XML

Segment Disclosures Recon from Segment to Consolidated - Revenues (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022		Dec. 31, 2021	Dec. 31, 2020
Segment revenues [Line Items]
Revenues		$ 10,965		$ 10,627	$ 7,719
Other financial information:
Additions to long-lived assets		3,598		1,855	1,283
Proportional Modified EBITDA Equity Method Investments		979		970	749
Intersegment Eliminations [Member]
Segment revenues [Line Items]
Revenues		(1,329)		(1,375)	(467)
Other financial information:
Additions to long-lived assets		0		0	0
Proportional Modified EBITDA Equity Method Investments		0		0	0
Operating Segments [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues		4,047		3,786	3,469
Other financial information:
Additions to long-lived assets		1,420		861	706
Proportional Modified EBITDA Equity Method Investments		193		183	166
Operating Segments [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues		1,802		1,634	1,529
Other financial information:
Additions to long-lived assets		261		164	137
Proportional Modified EBITDA Equity Method Investments		654		682	473
Operating Segments [Member] | West [Member]
Segment revenues [Line Items]
Revenues		2,561		2,026	1,523
Other financial information:
Additions to long-lived assets		1,507		209	318
Proportional Modified EBITDA Equity Method Investments		132		105	110
Operating Segments [Member] | Gas & NGL Marketing Services
Segment revenues [Line Items]
Revenues		3,233	[1]	4,211	1,631
Other financial information:
Additions to long-lived assets		4		1	0
Proportional Modified EBITDA Equity Method Investments		0		0	0
Operating Segments [Member] | Other [Member]
Segment revenues [Line Items]
Revenues		651		345	34
Other financial information:
Additions to long-lived assets		406		620	122
Proportional Modified EBITDA Equity Method Investments		0		0	0
Service [Member]
Segment revenues [Line Items]
Revenues		6,536		6,001	5,924
Service [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues		3,461		3,310	3,207
Service [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues		1,613		1,490	1,416
Service [Member] | West [Member]
Segment revenues [Line Items]
Revenues		1,443		1,178	1,248
Service [Member] | Gas & NGL Marketing Services
Segment revenues [Line Items]
Revenues		3	[1]	3	32
Service [Member] | Other [Member]
Segment revenues [Line Items]
Revenues		16		20	21
Service [Member] | Intersegment Eliminations [Member]
Segment revenues [Line Items]
Revenues		(266)		(195)	(136)
Service [Member] | Intersegment Eliminations [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues		(118)		(75)	(50)
Service [Member] | Intersegment Eliminations [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues		(41)		(38)	(49)
Service [Member] | Intersegment Eliminations [Member] | West [Member]
Segment revenues [Line Items]
Revenues		(99)		(70)	(24)
Service [Member] | Intersegment Eliminations [Member] | Gas & NGL Marketing Services
Segment revenues [Line Items]
Revenues		0	[1]	0	0
Service [Member] | Intersegment Eliminations [Member] | Other [Member]
Segment revenues [Line Items]
Revenues		(8)		(12)	(13)
Service [Member] | Operating Segments [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues		3,579		3,385	3,257
Service [Member] | Operating Segments [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues		1,654		1,528	1,465
Service [Member] | Operating Segments [Member] | West [Member]
Segment revenues [Line Items]
Revenues		1,542		1,248	1,272
Service [Member] | Operating Segments [Member] | Gas & NGL Marketing Services
Segment revenues [Line Items]
Revenues		3	[1]	3	32
Service [Member] | Operating Segments [Member] | Other [Member]
Segment revenues [Line Items]
Revenues		24		32	34
NonRegulated Service Commodity Consideration [Member]
Segment revenues [Line Items]
Revenues		260		238	129
NonRegulated Service Commodity Consideration [Member] | Intersegment Eliminations [Member]
Segment revenues [Line Items]
Revenues		0		0	0
NonRegulated Service Commodity Consideration [Member] | Operating Segments [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues		64		52	21
NonRegulated Service Commodity Consideration [Member] | Operating Segments [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues		14		7	7
NonRegulated Service Commodity Consideration [Member] | Operating Segments [Member] | West [Member]
Segment revenues [Line Items]
Revenues		182		179	101
NonRegulated Service Commodity Consideration [Member] | Operating Segments [Member] | Gas & NGL Marketing Services
Segment revenues [Line Items]
Revenues		0	[1]	0	0
NonRegulated Service Commodity Consideration [Member] | Operating Segments [Member] | Other [Member]
Segment revenues [Line Items]
Revenues		0		0	0
Product [Member]
Segment revenues [Line Items]
Revenues		4,556		4,536	1,671
Product [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues		228		231	144
Product [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues		28		13	16
Product [Member] | West [Member]
Segment revenues [Line Items]
Revenues		145		60	20
Product [Member] | Gas & NGL Marketing Services
Segment revenues [Line Items]
Revenues		4,052	[1]	4,094	1,491
Product [Member] | Other [Member]
Segment revenues [Line Items]
Revenues		103		138	0
Product [Member] | Intersegment Eliminations [Member]
Segment revenues [Line Items]
Revenues		(1,063)		(1,180)	(331)
Product [Member] | Intersegment Eliminations [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues		(176)		(118)	(47)
Product [Member] | Intersegment Eliminations [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues		(106)		(86)	(41)
Product [Member] | Intersegment Eliminations [Member] | West [Member]
Segment revenues [Line Items]
Revenues		(696)		(583)	(132)
Product [Member] | Intersegment Eliminations [Member] | Gas & NGL Marketing Services
Segment revenues [Line Items]
Revenues		518	[1]	(198)	(111)
Product [Member] | Intersegment Eliminations [Member] | Other [Member]
Segment revenues [Line Items]
Revenues		(603)		(195)	0
Product [Member] | Operating Segments [Member] | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues		404		349	191
Product [Member] | Operating Segments [Member] | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues		134		99	57
Product [Member] | Operating Segments [Member] | West [Member]
Segment revenues [Line Items]
Revenues		841		643	152
Product [Member] | Operating Segments [Member] | Gas & NGL Marketing Services
Segment revenues [Line Items]
Revenues		3,534	[1]	4,292	1,602
Product [Member] | Operating Segments [Member] | Other [Member]
Segment revenues [Line Items]
Revenues		706		333	0
Energy Commodities and Service
Segment revenues [Line Items]
Revenues	[2]	(387)		(148)	(5)
Energy Commodities and Service | Realized Gain (Loss)
Segment revenues [Line Items]
Revenues		(91)		(39)	(5)
Energy Commodities and Service | Unrealized Gain (Loss)
Segment revenues [Line Items]
Revenues		(296)		(109)	0
Energy Commodities and Service | Transmission And Gulf Of Mexico [Member]
Segment revenues [Line Items]
Revenues	[2]	0		0	0
Energy Commodities and Service | Transmission And Gulf Of Mexico [Member] | Realized Gain (Loss)
Segment revenues [Line Items]
Revenues		0		0	0
Energy Commodities and Service | Transmission And Gulf Of Mexico [Member] | Unrealized Gain (Loss)
Segment revenues [Line Items]
Revenues		0		0	0
Energy Commodities and Service | Northeast G And P [Member]
Segment revenues [Line Items]
Revenues	[2]	0		0	0
Energy Commodities and Service | Northeast G And P [Member] | Realized Gain (Loss)
Segment revenues [Line Items]
Revenues		0		0	0
Energy Commodities and Service | Northeast G And P [Member] | Unrealized Gain (Loss)
Segment revenues [Line Items]
Revenues		0		0	0
Energy Commodities and Service | West [Member]
Segment revenues [Line Items]
Revenues	[2]	(4)		(44)	(2)
Energy Commodities and Service | West [Member] | Realized Gain (Loss)
Segment revenues [Line Items]
Revenues		(4)		(44)	(2)
Energy Commodities and Service | West [Member] | Unrealized Gain (Loss)
Segment revenues [Line Items]
Revenues		0		0	0
Energy Commodities and Service | Gas & NGL Marketing Services
Segment revenues [Line Items]
Revenues	[2]	(304)		(84)	(3)
Energy Commodities and Service | Gas & NGL Marketing Services | Realized Gain (Loss)
Segment revenues [Line Items]
Revenues		17		25	(3)
Energy Commodities and Service | Gas & NGL Marketing Services | Unrealized Gain (Loss)
Segment revenues [Line Items]
Revenues		(321)		(109)	0
Energy Commodities and Service | Other [Member]
Segment revenues [Line Items]
Revenues	[2]	(79)		(20)	0
Energy Commodities and Service | Other [Member] | Realized Gain (Loss)
Segment revenues [Line Items]
Revenues		(104)		(20)	0
Energy Commodities and Service | Other [Member] | Unrealized Gain (Loss)
Segment revenues [Line Items]
Revenues		25		0	0
Energy Commodities and Service | Intersegment Eliminations [Member]
Segment revenues [Line Items]
Revenues	[2]	0		0	0
Energy Commodities and Service | Intersegment Eliminations [Member] | Realized Gain (Loss)
Segment revenues [Line Items]
Revenues		0		0	0
Energy Commodities and Service | Intersegment Eliminations [Member] | Unrealized Gain (Loss)
Segment revenues [Line Items]
Revenues		$ 0		$ 0	$ 0

[1] See Note 1 – General, Description of Business, Basis of Presentation, and Summary of Significant Accounting Policies.

[2] We record transactions that qualify as derivatives at fair value with changes in fair value recognized in earnings in the period of change and characterized as unrealized gains or losses. Gains and losses on derivatives held for energy trading purposes are presented on a net basis in revenue.

XML

Segment Disclosures Recon from Segment to Consolidated - Assets and Investments (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ 48,433	$ 47,612
Equity-method investments	5,048	5,121
Current assets	3,797	4,549
Other Assets, Noncurrent	1,319	1,276
Operating Segments [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	43,317	41,787
Equity-method investments	5,048	5,121
Operating Segments [Member] | Transmission And Gulf Of Mexico [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	17,795	17,142
Equity-method investments	629	602
Operating Segments [Member] | Northeast G And P [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	13,539	13,861
Equity-method investments	3,566	3,681
Operating Segments [Member] | West [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	10,710	9,698
Equity-method investments	843	838
Operating Segments [Member] | Gas & NGL Marketing Services
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	130	294
Equity-method investments	0	0
Operating Segments [Member] | Other [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	1,143	792
Equity-method investments	$ 10	$ 0

XML

Subsequent Events (Details) - USD ($) $ / shares in Units, $ in Millions			12 Months Ended
	Feb. 14, 2023	Jan. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Subsequent Event [Line Items]
Common Stock, Dividends, Per Share, Declared			$ 1.70	$ 1.64	$ 1.60
Subsequent Event [Member]
Subsequent Event [Line Items]
Common Stock, Dividends, Per Share, Declared		$ 0.4475
Subsequent Event [Member] | MountainWestAcquisition
Subsequent Event [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	100.00%
Business Combination, Consideration Transferred	$ 1,080
Business Combination, Consideration Transferred, Liabilities Incurred	$ 430

XML

Schedule II Valuation and Qualifying Accounts (Details) - Deferred Tax Asset Valuation Allowance [Member] - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Valuation And Qualifying Accounts
Beginning Balance	[1]	$ 297	$ 325	$ 319
Additions Charged (Credited) To Cost and Expenses		(97)	(28)	6
Additions Other		0	0	0
Deductions		0	0	0
Ending Balance	[1]	$ 200	$ 297	$ 325

[1] Deducted from related assets.